Building energy optimization system with economic load demand response (eldr) optimization and eldr user interfaces

ABSTRACT

An energy optimization system for a building includes a processing circuit configured to generate a user interface including an indication of one or more economic load demand response (energy) operation parameters, one or more first participation hours, and a first load reduction amount for each of the one or more first participation hours. The processing circuit is configured to receive one or more overrides of the one or more first participation hours from the user interface, generate one or more second participation hours, a second load reduction amount for each of the one or more second participation hours, and one or more second equipment loads for the one or more pieces of building equipment based on the received one or more overrides, and operate the one or more pieces of building equipment to affect an environmental condition of the building based on the one or more second equipment loads.

CROSS-REFERENCE TO RELATED PATENT APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.15/974,443 filed May 8, 2018, which is a continuation-in-part of U.S.patent application Ser. No. 15/616,616 filed Jun. 7, 2017 (U.S. Pat. No.10,949,777), both of which are incorporated herein by reference in theirentirety.

BACKGROUND

The present disclosure relates generally to an energy cost optimizationsystem for a building, a collection of buildings, or a central plant.The present disclosure relates more particularly to an energy costoptimization system that accounts for revenue generated fromparticipating in incentive-based demand response (IBDR) programs.

IBDR programs include various incentive-based programs such as frequencyregulation (FR) and economic load demand response (ELDR). An ELDRprogram is typically operated by a regional transmission organization(RTO) and/or an independent system operator (ISO). The RTO and/or ISOmay reward a customer for reducing their electric load during certainhours of the day. The RTO and/or ISO may operate with a bidding systemin which various customers place bids with the RTO and/or ISO to reducetheir electric load during selected hours. Based on the received bids,the RTO and/or ISO may dispatch awarded hours to the various customers.

Customers that participate in the ELDR program can either be awarded orpenalized by the RTO and/or ISO based on the electric load of thecustomer during awarded hours (i.e., hours on which the customer has bidand been awarded). A customer may include a curtailment amount in theirbid. A curtailment amount may be an amount that the customer will reducetheir electric load with respect to a baseline load. If the customercurtails their electric load according to their bid during the awardedhours, the customer is compensated. However, if the customer does notcurtail their electric load according to their bid during the awardedhours, the customer is penalized.

SUMMARY

One implementation of the present disclosure is an energy costoptimization system for a building. The system includes HVAC equipmentconfigured to operate in the building and a controller. The controlleris configured to generate a cost function defining a cost of operatingthe HVAC equipment over an optimization period as a function of one ormore electric loads setpoints for the HVAC equipment. The electric loadsetpoints are decision variables of the cost function and are setpointsfor each hour of the optimization period. The controller is furtherconfigured to generate participation hours. The participation hoursindicate one or more hours that the HVAC equipment will participate inan economic load demand response (ELDR) program. The controller isfurther configured to generate an ELDR term based on the participationhours. The ELDR term indicates revenue generated by participating in theELDR program. The controller is further configured to modify the costfunction to include the ELDR term and perform an optimization using themodified cost function to determine optimal electric load setpoints foreach hour of the participation hours.

In some embodiments, the controller is configured to generate a bid forparticipation in the ELDR program by subtracting the optimal electricload setpoints from a customer baseline load (CBL) for each hour of theparticipation hours and generating the bid to be the participation hoursexcluding certain hours of the participation hours. In some embodiments,the certain hours are hours where the difference of the CBL and theoptimal electric load setpoint are less than or equal to zero. Thecontroller can be further configured to send the bid to an incentiveprogram. In some embodiments, the controller is configured to cause theHVAC equipment to operate based on awarded participation hours receivedfrom the incentive program and the optimal electric loads.

In some embodiments, the controller is configured to modify the costfunction to include the ELDR term by representing participation in theELDR program as an electric rate adjustment in the cost function. Theelectric rate adjustment may be dependent on at least one of theparticipation hours, a CBL, a predicted day-ahead locational marginalprice (LMP), and a predicted real-time LMP. In some embodiments, thecontroller is configured to perform the optimization using the modifiedcost function to determine the optimal electric load for each hour ofthe participation hours based on the electric rate adjustment.

In some embodiments, the controller is configured to receive a netbenefit test (NBT), a LMP, and a real-time LMP from an incentiveprogram. The controller can further be configured to generate theparticipation hours by comparing the NBT to a predicted day-ahead LMPthat is based on one or more received day-ahead LMPs and a predictedreal-time LMP that is based on one or more received real-time LMP.

In some embodiments, the controller is configured to generate theparticipation hours by comparing an NBT to a predicted day-ahead LMP anda predicted real-time LMP and determining values for an event start hourand an event end hour that cause an equation to be minimized anddetermining that the participation hours are the hours between the eventstart hour and the event end hour. In some embodiments, the equationincludes at least one of a customer baseline load (CBL), a predictedreal-time LMP, and a predicted electric load. In some embodiments, theparticipation hours are used as the search space for minimizing theequation and are the hours generated by comparing the NBT to one or bothof the predicted day-ahead LMP and the predicted real-time LMP.

In some embodiments, the CBL is dependent on the event start hour andthe event end hour. The CBL may be at least one of a same day CBL and asymmetric additive adjustment (SAA) CBL.

In some embodiments, the CBL is an SAA CBL and the controller isconfigured to determine the SAA CBL by determining an average electricload to be the average electric load of four weekdays of five mostrecently occurring weekdays before the participation hours if theparticipation hours occur on a weekday, determining the average electricload to be the average electric load two weekends or holidays of threemost recently occurring weekends or holidays, if the participation hoursoccur on a weekend or holiday, determining an adjustment based onpredicted electric loads of three consecutive hours one hour before theevent start hour, and determining the SAA CBL to be the sum of theaverage electric load and the adjustment.

In some embodiments, the CBL is a same day CBL. In some embodiments, thecontroller is configured to determine the same day CBL based onpredicted electric loads three consecutive hours one hour before theparticipation hours and predicted electric loads two consecutive hoursone hour after the participation hours.

In some embodiments, the participation hours are a vector of ones andzeros for a plurality of hours, a one indicates participation in theELDR program for a particular hour while a zero indicates noparticipation in the ELDR program for a particular hour. In someembodiments, the modified cost function represents participation in theELDR program as an electric rate adjustment.

Another implementation of the present disclosure is a method foroptimizing energy costs for a building. The method includes generating acost function defining a cost of operating HVAC equipment over anoptimization period as a function of one or more electric loads for theHVAC equipment. The electric loads are decision variables of the costfunction and include an electric load for each hour of the optimizationperiod. The method further includes generating participation hours, theparticipation hours indicate one or more hours that the HVAC equipmentwill participate in an economic load demand response (ELDR) program. Themethod further includes generating an ELDR term based on theparticipation hours. The ELDR term indicates revenue generated byparticipating in the ELDR program. The method further includes modifyingthe cost function to include the ELDR term and performing anoptimization using the modified cost function to determine an optimalelectric load for each hour of the participation hours.

In some embodiments, the method further includes generating a bid forparticipation in the ELDR program by subtracting the optimal electricload from a customer baseline load (CBL) for each hour of theparticipation hours and generating the bid to be the participation hoursexcluding certain hours of the participation hours. In some embodiments,the certain hours are hours where the difference of the CBL and theoptimal electric load is less than or equal to zero. In someembodiments, the method further includes sending the bid to an incentiveprogram. In some embodiments, the method further includes causing theHVAC equipment to operate based on the awarded participation hours andthe optimal electric load setpoints. In some embodiments, the modifiedcost function represents participation in the ELDR program as anelectric rate adjustment.

In some embodiments, modifying the cost function to include the ELDRterm comprises representing participation in the ELDR program as anelectric rate adjustment in the cost function. The electric rateadjustment may be dependent on at least one of the participation hours,a CBL, a predicted day-ahead locational marginal price (LMP), and apredicted real-time LMP. In some embodiments, performing theoptimization using the modified cost function to determine the optimalelectric load for each hour of the participation hours is based on theelectric rate adjustment.

In some embodiments, the method further includes receiving a net benefittest (NBT), a day-ahead LMP, and a real-time LMP from an incentiveprogram. In some embodiments, the method further includes generating theparticipation hours by comparing the NBT to a predicted day-ahead LMPthat is based on one or more received day-ahead LMPs and a predictedreal-time LMP that is based on one or more received real-time LMP.

In some embodiments, the method includes determining the participationhours by comparing an NBT to at least one of a predicted day-ahead LMPand a predicted real-time LMP. In some embodiments, the method includesdetermining values for an event start hour and an event end hour thatcause an equation to be minimized, the equation including at least oneof a customer baseline load (CBL), a predicted real-time LMP, and apredicted electric load. The participation hours may be used as thesearch space for minimizing the equation and may be the hours generatedby comparing the NBT to at least one of the predicted day-ahead LMP andthe predicted real-time LMP. In some embodiments, the method includesdetermining that the participation hours are the hours between the eventstart hour and the event end hour.

In some embodiments, the method further includes determining the SAA CBLby determining an average electric load to be the average electric loadof four weekdays of five most recently occurring weekdays before theparticipation hours if the participation hours occur on a weekday,determining the average electric load to be the average electric load oftwo weekends or holidays of three most recently occurring weekends orholidays if the participation hours occur on a weekend or holiday,determining an adjustment based on predicted electric loads of threeconsecutive hours one hour before the event start hour, and determiningthe SAA CBL to be the sum of the average electric load and theadjustment.

In some embodiments, the CBL is a same day CBL. In some embodiments, themethod further includes determining the same day CBL based on predictedelectric loads three consecutive hours one hour before the participationhours and predicted electric loads two consecutive hours one hour afterthe participation hours.

Another implementation of the present disclosure is an energy costoptimization system for a building. The system includes HVAC equipmentconfigured to satisfy a building energy load of the building and acontroller. The controller is configured to generate a cost functiondefining a cost of operating the HVAC equipment over an optimizationperiod as a function of one or more electric loads for the HVACequipment. The electric loads are decision variables of the costfunction and include an electric load for each hour of the optimizationperiod. The controller can be configured to receive a net benefit test(NBT), a day-ahead locational marginal price (LMP), and a real-time LMPfrom an incentive program. The controller can be configured to generateparticipation hours. The participation hours indicate one or more hoursthat the HVAC equipment will participate in an economic load demandresponse (ELDR) program. The controller can be configured to generatethe participation hours by comparing the NBT to a predicted day-aheadLMP that is based on one or more received day-ahead LMPs and a predictedreal-time LMP that is based on one or more received real-time LMP. Thecontroller is configured to generate an ELDR term based on theparticipation hours. The ELDR term indicates revenue generated byparticipating in the ELDR program. The controller is configured tomodify the cost function to include the ELDR term and perform anoptimization using the modified cost function to determine an optimalelectric load for each hour of the participation hours.

In some embodiments, the controller is configured to generate a bid forparticipation in the ELDR program by subtracting the optimal electricload from a customer baseline load (CBL) for each hour of theparticipation hours and generating the bid to be the participation hoursexcluding certain hours of the participation hours. In some embodiments,the certain hours are hours where the difference of the CBL and theoptimal electric load is less than or equal to zero. The controller canbe configured to send the bid to an incentive program and cause the HVACequipment to operate based on awarded participation hours received fromthe incentive program and the optimal electric loads.

In some embodiments, the controller is configured to determine theparticipation hours by determining values for an event start hour and anevent end hour that cause an equation to be minimized. In someembodiments, the equation includes at least one of a customer baselineload (CBL), a predicted real-time LMP, and a predicted electric load. Insome embodiments, the participation hours are used as the search spacefor minimizing the equation and are the hours generated by comparing theNBT to the predicted day-ahead LMP and the predicted real-time LMP. Insome embodiments, the controller is configured to determine theparticipation hours by determining that the participation hours are thehours between the event start hour and the event end hour.

In some embodiments, the CBL is an SAA CBL or a same day CBL. In someembodiments, the controller is configured to determine the SAA CBL bydetermining an average electric load to be the average electric load offour weekdays of five most recently occurring weekdays before theparticipation hours, if the participation hours occur on a weekday,determining the average electric load to be the average electric load oftwo weekends or holidays of three most recently occurring weekends orholidays, if the participation hours occur on a weekend or holiday,determining an adjustment based on predicted electric loads of threeconsecutive hours one hour before the event start hour, and determiningthe SAA CBL to be the sum of the average electric load and theadjustment. The controller can be configured to determine the same dayCBL based on predicted electric loads three consecutive hours one hourbefore the participation hours and predicted electric loads twoconsecutive hours one hour after the participation hours.

One implementation of the present disclosure is an energy optimizationsystem for a building. The system includes a processing circuitconfigured to perform an optimization to generate one or more firstparticipation hours and a first load reduction amount for reach of theone or more first participation hours and provide a first bid includingthe one or more first participation hours and the first load reductionamount for each of the one or more first participation hours to acomputing system configured to facilitate an economic load demandresponse (ELDR) program. The processing circuit is configured to operateone or more pieces of building equipment to affect an environmentalcondition of the building based on one or more first equipment loads forparticipating in the ELDR program and receive one or more awarded orrejected participation hours from the computing system responsive to thefirst bid. The processing circuit is configured to generate one or moresecond participation hours for participating in the ELDR program, asecond load reduction amount for each of the one or more secondparticipation hours, and one or more second equipment loads for the oneor more pieces of building equipment based on the one or more awarded orrejected participation hours by performing the optimization a secondtime and operate the one or more pieces of building equipment to affectthe environmental condition of the building based on the one or moresecond equipment loads.

In some embodiments, the processing circuit is configured to generate apredicted campus electric load based on at least one of historicalcampus electric load values, predicted market resource prices, predictedequipment loads, or predicted chilled water loads and generate the oneor more second participation hours for participating in the ELDRprogram, the second load reduction amount for each of the one or moresecond participation hours, and the one or more second equipment loadsfor the one or more pieces of building equipment based on the one ormore awarded or rejected participation hours and on the predicted campuselectric load by performing the optimization the second time.

In some embodiments, the processing circuit is configured to generate asecond bid including the one or more second participation hours and thesecond load reduction amount for each of the one or more secondparticipation hours, provide the second bid to the computing systemconfigured to facilitate the ELDR program, and receive one or moresecond awarded or rejected hours from the computing system responsive tothe second bid.

In some embodiments, the second bid is an update to the first bid, theone or more second participation hours are an update to the one or morefirst participation hours, and the second load reduction amount for eachof the one or more second participation hours is an update to the firstload reduction amount for each of the one or more first participationhours.

In some embodiments, the one or more awarded or rejected hours and theone or more second participation hours are hours of a particular day,wherein the processing circuit is configured to determine a revenuebenefit for the particular day based on a benefit function and the oneor more awarded or rejected hours and determine whether to participatein the ELDR program for the particular day based on a comparison of therevenue benefit to a predefined threshold.

In some embodiments, the processing circuit is configured to determinewhether to participate in the ELDR program for the particular day basedon the comparison of the revenue benefit to the predefined threshold bydetermining to participate in the ELDR program for the particular day inresponse to a determination that the revenue benefit is greater than thepredefined threshold and determining not to participate in the ELDRprogram for the particular day in response to a determination that therevenue benefit is less than the predefined threshold.

In some embodiments, the processing circuit is configured to perform theoptimization to generate the one or more first participation hours forparticipating in the ELDR program, the first load reduction amount foreach of the one or more first participation hours, and the one or morefirst equipment loads for the one or more pieces of building equipmentbased on one or more ELDR parameters for the ELDR program.

In some embodiments, the one or more ELDR parameters include at leastone of a day ahead locational marginal price which is an electricityprice for a particular area on a future day, a real-time locationalmarginal price which is an electricity price at a current time, or a netbenefits test which is a value indicating whether a particular hourshould be a participation hour.

In some embodiments, the processing circuit is configured toperiodically collect one or more ELDR parameters from the computingsystem configured to facilitate the ELDR program and generate the one ormore second participation hours for participating in the ELDR program,the second load reduction amount for each of the one or more secondparticipation hours, and the one or more second equipment loads for theone or more pieces of building equipment based on the one or more firstawarded or rejected hours and the periodically collected ELDR parametersby performing the optimization the second time.

In some embodiments, the processing circuit is configured to generateone or more predictions of the one or more ELDR parameters based on theone or more ELDR parameters and generate the one or more secondparticipation hours for participating in the ELDR program, the secondload reduction amount for each of the one or more second participationhours, and the one or more second equipment loads for the one or morepieces of building equipment based on the one or more first awarded orrejected hours and the one or more predictions of the one or more ELDRparameters by performing the optimization the second time.

Another implementation of the present disclosure is a method foroptimizing energy use of a building. The method includes performing anoptimization to generate one or more first participation hours and afirst load reduction amount for reach of the one or more firstparticipation hours. The method includes providing a first bid includingthe one or more first participation hours and the first load reductionamount for each of the one or more first participation hours to acomputing system configured to facilitate an economic load demandresponse (ELDR) program, operating one or more pieces of buildingequipment to affect an environmental condition of the building based onone or more first equipment loads for participating in the ELDR program,and receiving one or more awarded or rejected participation hours fromthe computing system in response to providing the first bid to thecomputing system. The method includes generating one or more secondparticipation hours for participating in the ELDR program, a second loadreduction amount for each of the one or more second participation hours,and one or more second equipment loads for the one or more pieces ofbuilding equipment based on the one or more awarded or rejectedparticipation hours by performing the optimization a second time andoperating the one or more pieces of building equipment to affect theenvironmental condition of the building based on the one or more secondequipment loads.

In some embodiments, the method includes generating a predicted campuselectric load based on at least one of historical campus electric loadvalues, predicted market resource prices, predicted equipment loads, orpredicted chilled water loads and generating the one or more secondparticipation hours for participating in the ELDR program, the secondload reduction amount for each of the one or more second participationhours, and the one or more second equipment loads for the one or morepieces of building equipment based on the one or more awarded orrejected participation hours and on the predicted campus electric load.

In some embodiments, the method includes generating a second bidincluding the one or more second participation hours and the second loadreduction amount for each of the one or more second participation hours,providing the second bid to the computing system configured tofacilitate the ELDR program, wherein the second bid is an update to thefirst bid, the one or more second participation hours are an update tothe one or more first participation hours, and the second load reductionamount for each of the one or more second participation hours is anupdate to the first load reduction amount for each of the one or morefirst participation hours and receiving one or more second awarded orrejected hours from the computing system in response to providing thesecond bid.

In some embodiments, the one or more awarded or rejected hours and theone or more second participation hours are hours of a particular day. Insome embodiments, the method includes determining a revenue benefit forthe particular day based on a benefit function and the one or moreawarded or rejected hours and determining whether to participate in theELDR program for the particular day based on a comparison of the revenuebenefit to a predefined threshold.

In some embodiments, determining whether to participate in the ELDRprogram for the particular day based on a comparison of the revenuebenefit to a predefined threshold includes determining to participate inthe ELDR program for the particular day in response to a determinationthat the revenue benefit is greater than the predefined threshold anddetermining not to participate in the ELDR program for the particularday in response to a determination that the revenue benefit is less thanthe predefined threshold.

In some embodiments, the method includes performing the optimization togenerate the one or more first participation hours for participating inthe ELDR program, the first load reduction amount for each of the one ormore first participation hours, and the one or more first equipmentloads for the one or more pieces of building equipment is based on oneor more ELDR parameters for the ELDR program.

In some embodiments, the method includes periodically collecting the oneor more ELDR parameters from the computing system configured tofacilitate the ELDR program, generating one or more predictions of theone or more ELDR parameters based on the one or more ELDR parameters,and generating the one or more second participation hours forparticipating in the ELDR program, the second load reduction amount foreach of the one or more second participation hours, and the one or moresecond equipment loads for the one or more pieces of building equipmentbased on the one or more first awarded or rejected hours and the one ormore predictions of the one or more ELDR parameters by performing theoptimization the second time.

Another implementation of the present disclosure is an energyoptimization controller for a building. The controller includes aprocessing circuit configured to perform an optimization to generate oneor more first participation hours and a first load reduction amount foreach of the one or more first participation hours and provide a firstbid including the one or more first participation hours and the firstload reduction amount for each of the one or more first participationhours to a computing system configured to facilitate an economic loaddemand response (ELDR) program. The processing circuit is configured tooperate the one or more pieces of building equipment to affect anenvironmental condition of the building based on one or more firstequipment loads for participating in the ELDR program, receive one ormore awarded or rejected participation hours from the computing system,periodically collect one or more ELDR parameters from the computingsystem configured to facilitate the ELDR program, generate one or morepredictions of the one or more ELDR parameters based on the one or moreELDR parameters, generate one or more second participation hours forparticipating in the ELDR program, a second load reduction amount foreach of the one or more second participation hours, and one or moresecond equipment loads for the one or more pieces of building equipmentbased on the one or more awarded or rejected participation hours and thepredicted one or more ELDR parameters, and operate the one or morepieces of building equipment to affect the environmental condition ofthe building based on the one or more second equipment loads.

In some embodiments, the one or more awarded or rejected hours and theone or more participation hours are hours of a particular day, whereinthe processing circuit is configured to determine a revenue benefit forthe particular day based on a benefit function and the one or moreawarded or rejected hours and determine whether to participate in theELDR program for the particular day based on a comparison of the revenuebenefit to a predefined threshold.

In some embodiments, the processing circuit is configured to determinewhether to participate in the ELDR program for the particular day basedon a comparison of the revenue benefit to a predefined threshold bydetermining to participate in the ELDR program for the particular day inresponse to a determination that the revenue benefit is greater than thepredefined threshold and determining not to participate in the ELDRprogram for the particular day in response to a determination that therevenue benefit is less than the predefined threshold.

Another implementation of the present disclosure is an energyoptimization system for a building. The system includes a processingcircuit configured to perform an optimization to generate one or morefirst participation hours and a first load reduction amount for each ofthe one or more first participation hours and generate a user interfaceincluding an indication of one or more economic load demand response(ELDR) operation parameters for an ELDR program, the one or more firstparticipation hours, and the first load reduction amount for each of theone or more first participation hours. The processing circuit isconfigured to receive one or more overrides of the one or more firstparticipation hours from the user interface, perform the optimization asecond time to generate one or more second participation hours forparticipating in the ELDR program, a second load reduction amount foreach of the one or more second participation hours, and one or moresecond equipment loads for the one or more pieces of building equipmentbased on the received one or more overrides, and operate the one or morepieces of building equipment to affect an environmental condition of thebuilding based on the one or more second equipment loads.

In some embodiments, the processing circuit is configured to provide afirst bid including the one or more first participation hours and thefirst load reduction amount for each of the one or more firstparticipation hours to a computing system configured to facilitate theELDR program and provide a second bid including the one or more secondparticipation hours and the second load reduction amount for each of theone or more second participation hours to the computing systemconfigured to facilitate the ELDR program, wherein the second bid is anupdate to the first bid, the one or more second participation hours arean update to the one or more first participation hours, and the secondload reduction amount for each of the one or more second participationhours is an update to the first load reduction amount for each of theone or more first participation hours.

In some embodiments, the user interface includes a first interfaceelement indicating values for the one or more ELDR parameters and asecond interface element indicating the one or more first participationhours and the first load reduction amount for each of the one or morefirst participation hours.

In some embodiments, the second interface element is a chart indicatinga plurality of hours for a plurality of days and an indication of whichof the plurality of hours for the plurality of days are the firstparticipation hours and the first load reduction amount for each of theone or more first participation hours.

In some embodiments, the processing circuit is configured to display alocked indication for each of the one or more first participation hoursa predefined amount of time before each of the one or more participationhours occurs and prevent a user from overriding each of the one or morefirst participation hours within the predefined amount of time beforeeach of the one or more first participation hours.

In some embodiments, the first interface element is a trend graphindicating a trend of the values for the one or more ELDR parameters fora plurality of times. In some embodiments, the processing circuit isconfigured to collect the values for the one or more ELDR operationparameters from a computing system configured to facilitate the ELDRprogram, generate the trend graph based on the collected values for theone or more ELDR operation parameters, and cause the user interface toinclude the generated trend graph.

In some embodiments, the one or more ELDR parameters include at leastone of a day ahead locational marginal price which is an electricityprice for a particular area on a future day, or a real-time locationalmarginal price which is an electricity price on at a current time.

In some embodiments, the processing circuit is configured to receive oneor more electric consumption values from building equipment configuredto measure the electrical consumption values, cause the trend graph toinclude a trend of the one or more electric consumption values, generatea baseline electrical load based on historic electric load consumption,and cause the trend graph to include an indication of the baselineelectrical load.

Another implementation of the present disclosure is a method foroptimizing energy use of a building. The method includes performing anoptimization to generate one or more first participation hours and afirst load reduction amount for each of the one or more firstparticipation hours. The method includes generating a user interfaceincluding an indication of one or more economic load demand response(ELDR) operation parameters for an ELDR program, the one or more firstparticipation hours, and the first load reduction amount for each of theone or more first participation hours, receiving one or more overridesof the one or more first participation hours from the user interface,performing the optimization a second time to generate one or more secondparticipation hours for participating in the ELDR program, a second loadreduction amount for each of the one or more second participation hours,and one or more second equipment loads for the one or more pieces ofbuilding equipment based on the received one or more overrides, andoperating the one or more pieces of building equipment to affect anenvironmental condition of the building based on the one or more secondequipment loads.

In some embodiments, the method includes providing a first bid includingthe one or more first participation hours and the first load reductionamount for each of the one or more first participation hours to acomputing system configured to facilitate the ELDR program and providinga second bid including the one or more second participation hours andthe second load reduction amount for each of the one or more secondparticipation hours to the computing system configured to facilitate theELDR program, wherein the second bid is an update to the first bid, theone or more second participation hours are an update to the one or morefirst participation hours, and the second load reduction amount for eachof the one or more second participation hours is an update to the firstload reduction amount for each of the one or more first participationhours.

In some embodiments, the user interface includes a first interfaceelement indicating values for the one or more ELDR parameters and asecond interface element indicating the one or more first participationhours and the first load reduction amount for each of the one or morefirst participation hours.

In some embodiments, the one or more ELDR parameters include one or moreawarded or rejected hours of the one or more first participation hours.In some embodiments, the processing circuit is configured to cause thesecond interface element to display an indication of which of the one ormore first participation hours are awarded hours or which of the one ormore first participation hours are rejected hours.

In some embodiments, the second interface element is a chart indicatinga hours for a plurality of days and an indication of which of theplurality of hours for the plurality of days are the first participationhours and the first load reduction amount for each of the one or morefirst participation hours.

In some embodiments, the method includes displaying a locked indicationfor each of the one or more first participation hours a predefinedamount of time before each of the one or more participation hours occursand preventing a user from overriding each of the one or more firstparticipation hours within the predefined amount of time before each ofthe one or more first participation hours.

In some embodiments, the first interface element is a trend graphindicating a trend of the values for the one or more ELDR parameters fora multiple times. In some embodiments, the method further includescollecting the values for the one or more ELDR operation parameters froma computing system configured to facilitate the ELDR program, generatingthe trend graph based on the collected values for the one or more ELDRoperation parameters, and causing the user interface to include thegenerated trend graph.

In some embodiments, the one or more ELDR parameters include at leastone of a day ahead locational marginal price which is an electricityprice for a particular area on a future day, or a real-time locationalmarginal price which is an electricity price on at a current time.

In some embodiments, the method includes receiving one or more electricconsumption values from building equipment configured to measure theelectrical consumption values, causing the trend graph to include atrend of the one or more electric consumption values, generating abaseline electrical load based on historic electric load consumption,and causing the trend graph to include an indication of the baselineelectrical load.

Another implementation of the present disclosure is an energyoptimization controller for a building. The controller includes aprocessing circuit configured to perform an optimization to generate oneor more first participation hours and a first load reduction amount foreach of the one or more first participation hours and generate a userinterface including an indication of one or more economic load demandresponse (ELDR) operation parameters for an ELDR program, the one ormore first participation hours, and the first load reduction amount foreach of the one or more first participation hours, wherein the userinterface includes a first interface element indicating values for theone or more ELDR parameters and a second interface element indicatingthe one or more first participation hours and the first load reductionamount for each of the one or more first participation hours, receiveone or more overrides of the one or more first participation hours fromthe user interface, perform the optimization a second time to generateone or more second participation hours for participating in the ELDRprogram, a second load reduction amount for each of the one or moresecond participation hours, and one or more second equipment loads forthe one or more pieces of building equipment based on the received oneor more overrides, and operate the one or more pieces of buildingequipment to affect an environmental condition of the building based onthe one or more second equipment loads.

In some embodiments, the processing circuit is configured to provide afirst bid including the one or more first participation hours and thefirst load reduction amount for each of the one or more firstparticipation hours to a computing system configured to facilitate theELDR program and provide a second bid including the one or more secondparticipation hours and the second load reduction amount for each of theone or more second participation hours to the computing systemconfigured to facilitate the ELDR program, wherein the second bid is anupdate to the first bid, the one or more second participation hours arean update to the one or more first participation hours, and the secondload reduction amount for each of the one or more second participationhours is an update to the first load reduction amount for each of theone or more first participation hours.

In some embodiments, the second interface element is a chart indicatinga plurality of hours for a plurality of days and an indication of whichof the plurality of hours for the plurality of days are the firstparticipation hours and the first load reduction amount for each of theone or more first participation hours.

In some embodiments, the processing circuit is configured to display alocked indication for each of the one or more first participation hoursa predefined amount of time before each of the one or more participationhours occurs and prevent a user from overriding each of the one or morefirst participation hours within the predefined amount of time beforeeach of the one or more first participation hours.

BRIEF DESCRIPTION OF THE DRAWINGS

Various objects, aspects, features, and advantages of the disclosurewill become more apparent and better understood by referring to thedetailed description taken in conjunction with the accompanyingdrawings, in which like reference characters identify correspondingelements throughout. In the drawings, like reference numbers generallyindicate identical, functionally similar, and/or structurally similarelements.

FIG. 1 is a block diagram of a frequency response optimization system,according to an exemplary embodiment.

FIG. 2 is a graph of a regulation signal which may be provided to thesystem of FIG. 1 and a frequency response signal which may be generatedby the system of FIG. 1, according to an exemplary embodiment.

FIG. 3 is a block diagram of a photovoltaic energy system configured tosimultaneously perform both ramp rate control and frequency regulationwhile maintaining the state-of-charge of a battery within a desiredrange, according to an exemplary embodiment.

FIG. 4 is a drawing illustrating the electric supply to an energy gridand electric demand from the energy grid which must be balanced in orderto maintain the grid frequency, according to an exemplary embodiment.

FIG. 5A is a block diagram of an energy storage system including thermalenergy storage and electrical energy storage, according to an exemplaryembodiment.

FIG. 5B is a block diagram of an energy cost optimization system withoutthermal or electrical energy storage, according to an exemplaryembodiment.

FIG. 6A is block diagram of an energy storage controller which may beused to operate the energy storage system of FIG. 5A, according to anexemplary embodiment.

FIG. 6B is a block diagram of a controller which may be used to operatethe energy cost optimization system of FIG. 5B, according to anexemplary embodiment.

FIG. 7 is a block diagram of a planning tool which can be used todetermine the benefits of investing in a battery asset and calculatevarious financial metrics associated with the investment, according toan exemplary embodiment.

FIG. 8 is a drawing illustrating the operation of the planning tool ofFIG. 7, according to an exemplary embodiment.

FIG. 9 is a block diagram of a high level optimizer which can beimplemented as a component of the controllers of FIGS. 6A-6B or theplanning tool of FIG. 7, according to an exemplary embodiment.

FIG. 10 is a block diagram of a controller including components forparticipating in an economic load demand response (ELDR) program,according to an exemplary embodiment.

FIG. 11A is a flow diagram of a process for determining participationhours in the ELDR program and sending a bid to an incentive program,according to an exemplary embodiment.

FIG. 11B is a flow diagram of a process for generating and modifying acost function to determine optimal electric loads for participation inan ELDR program that can be performed by the controller of FIG. 10,according to an exemplary embodiment.

FIG. 12 is a graph illustrating electric load reduction forparticipation in an ELDR program, according to an exemplary embodiment.

FIG. 13 is a graph illustrating a same day customer baseline load (CBL)that can be determined by the controller of FIG. 10, according to anexemplary embodiment.

FIG. 14 is a graph illustrating a symmetric additive adjustment (SAA)CBL that can be determined by the controller of FIG. 10, according to anexemplary embodiment.

FIG. 15 is an interface for a user to adjust participation in an ELDRprogram, according to an exemplary embodiment.

FIG. 16 is an interface for a user to adjust participation in an ELDRprogram, the interface illustrating revenue generated by the ELDRprogram, according to an exemplary embodiment.

FIG. 17 is a block diagram of an ELDR module for participating in theELDR program, according to an exemplary embodiment.

FIG. 18A is a flow diagram of a process for dynamically andautomatically participating in the ELDR program via the ELDR module ofFIG. 17, according to an exemplary embodiment.

FIG. 18B is flow diagram of the process of FIG. 18A, according to anexemplary embodiment.

FIG. 19 is a flow diagram of a process that can be performed by the ELDRmodule of FIG. 17 for determining whether to participate in the ELDRprogram in response to receiving rejected bids, according to anexemplary embodiment.

FIG. 20 is a timeline of collection events for collecting ELDRparameters by the ELDR module of FIG. 17 and dispatch events received bythe ELDR module of FIG. 17, according to an exemplary embodiment.

FIG. 21 is another chart illustrating the participation in the ELDRprogram when the first hours of the ELDR program participation bid arerejected, according to an exemplary embodiment.

FIG. 22 is yet another chart illustrating the participation in the ELDRprogram when the first hours of the ELDR program participation bid arerejected, according to an exemplary embodiment.

FIG. 23 is an interface that the ELDR module of FIG. 17 can generate forthe ELDR program, according to an exemplary embodiment.

FIG. 24 is the interface of FIG. 23 illustrating various participationhours and participation amounts for multiple days into the future forparticipating in the ELDR program, according to an exemplary embodiment.

FIG. 25 is the interface of FIG. 23 illustrating overriddenparticipation hours and past participation hours, according to anexemplary embodiment.

FIG. 26 is the interface of FIG. 23 illustrating a small number ofparticipation hours and participation amounts for some days, accordingto an exemplary embodiment.

FIG. 27 is the interface of FIG. 23 illustrating a large number ofparticipation hours and participation amounts for some days, accordingto an exemplary embodiment.

FIG. 28 is another interface that the ELDR module of FIG. 17 cangenerate for the ELDR program, according to an exemplary embodiment.

FIG. 29 is an example of selecting and overriding various hours in theinterface of FIG. 28, according to an exemplary embodiment.

FIG. 30 is the interface of FIG. 28 illustrating a plot of ELDRparameters and an indication of overridden participation hours.

FIG. 31 is the interface of FIG. 28 illustrating plots of a real-timelocational marginal price (LMP) and a day ahead LMP, according to anexemplary embodiment.

DETAILED DESCRIPTION Overview

Referring generally to the FIGURES, systems, methods, and devices, areshown for a building energy optimization system, the optimization systemconfigured to participate in an economic load demand response (ELDR)program. As illustrated herein, a controller for a building isconfigured to facilitate the participation in the ELDR program. Thecontroller can be configured to determine a plurality of participationhours that the controller determines the building should participate inthe ELDR program. Based on the determined participation hours, thecontroller can be configured to dispatch a bid to an incentive program.The incentive program may be a program managed by a curtailment serviceprovider (CSP). The CSP may act as a medium between customers and theRTO and/or ISO. The CSP, RTO, and/or ISO may be one or more systems,servers, or computers that manage and/or operate the ELDR program. Theincentive program may award some and/or all hours of the bid to thecontroller and transmit an indication of the awarded hours to thecontroller.

The controller can be configured to generate the participation hoursbased on values called “locational marginal prices” (LMPs). The LMPs mayindicate a rate at which the controller will be compensated forcurtailing an electric load of a building. The LMPs may be received bythe controller. In various embodiments, the controller is configured touse the LMPs to determine which hours the controller should participatein the ELDR program. In some embodiments, based on LMP values receivedfor past days, the controller can be configured to predict future LMPvalues and generate the participation hours based on the predicted LMPvalues.

The controller can be configured to determine optimal electric loadbased on the participation hours. HVAC equipment, lighting equipment,and/or any other electric consuming or producing equipment in a buildingcan be operated to meet the electric load. In some embodiments, thecontroller is configured to generate a cost function which indicates thecost of operating HVAC equipment of a building over an optimizationperiod (e.g., a single day). The participation hours may be hours duringthe optimization period i.e., particular hours of a day that thecontroller has determined it should participate in the ELDR program. Thecontroller can be configured to optimize the cost function and determinea plurality of decision variables that indicate an electric load for theoptimization period, including the participation hours.

Based on the optimal electric loads, the controller can be configured todetermine a bid for particular participation hours of the optimizationperiod. The bid may include hours that the controller has determined itshould participate in the ELDR program and may further include acurtailment amount. The curtailment amount may be a difference betweenthe buildings typical electric load (e.g., a baseline) and the optimalelectric load determined by the controller. The typical electric load(e.g., baseline) may be determined based on a method specified by theRTO and/or ISO. The controller can be configured to receive awardedhours, one, some, or all of the hours included in the bid from the RTOand/or ISO. The controller can be configured to operate HVAC equipmentof the building based on the awarded hours. The controller can beconfigured to operate the HVAC equipment so that the electric load ofthe building meets the optimal electric loads.

Frequency Response Optimization

Referring now to FIG. 1, a frequency response optimization system 100 isshown, according to an exemplary embodiment. System 100 is shown toinclude a campus 102 and an energy grid 104. Campus 102 may include oneor more buildings 116 that receive power from energy grid 104. Buildings116 may include equipment or devices that consume electricity duringoperation. For example, buildings 116 may include HVAC equipment,lighting equipment, security equipment, communications equipment,vending machines, computers, electronics, elevators, or other types ofbuilding equipment.

In some embodiments, buildings 116 are served by a building managementsystem (BMS). A BMS is, in general, a system of devices configured tocontrol, monitor, and manage equipment in or around a building orbuilding area. A BMS can include, for example, a HVAC system, a securitysystem, a lighting system, a fire alerting system, and/or any othersystem that is capable of managing building functions or devices. Anexemplary building management system which may be used to monitor andcontrol buildings 116 is described in U.S. patent application Ser. No.14/717,593 filed May 20, 2015, the entire disclosure of which isincorporated by reference herein.

In some embodiments, campus 102 includes a central plant 118. Centralplant 118 may include one or more subplants that consume resources fromutilities (e.g., water, natural gas, electricity, etc.) to satisfy theloads of buildings 116. For example, central plant 118 may include aheater subplant, a heat recovery chiller subplant, a chiller subplant, acooling tower subplant, a hot thermal energy storage (TES) subplant, anda cold thermal energy storage (TES) subplant, a steam subplant, and/orany other type of subplant configured to serve buildings 116. Thesubplants may be configured to convert input resources (e.g.,electricity, water, natural gas, etc.) into output resources (e.g., coldwater, hot water, chilled air, heated air, etc.) that are provided tobuildings 116. An exemplary central plant which may be used to satisfythe loads of buildings 116 is described U.S. patent application Ser. No.14/634,609 filed Feb. 27, 2015, the entire disclosure of which isincorporated by reference herein.

In some embodiments, campus 102 includes energy generation 120. Energygeneration 120 may be configured to generate energy that can be used bybuildings 116, used by central plant 118, and/or provided to energy grid104. In some embodiments, energy generation 120 generates electricity.For example, energy generation 120 may include an electric power plant,a photovoltaic energy field, or other types of systems or devices thatgenerate electricity. The electricity generated by energy generation 120can be used internally by campus 102 (e.g., by buildings 116 and/orcentral plant 118) to decrease the amount of electric power that campus102 receives from outside sources such as energy grid 104 or battery108. If the amount of electricity generated by energy generation 120exceeds the electric power demand of campus 102, the excess electricpower can be provided to energy grid 104 or stored in battery 108. Thepower output of campus 102 is shown in FIG. 1 as P_(campus). P_(campus)may be positive if campus 102 is outputting electric power or negativeif campus 102 is receiving electric power.

Still referring to FIG. 1, system 100 is shown to include a powerinverter 106 and a battery 108. Power inverter 106 may be configured toconvert electric power between direct current (DC) and alternatingcurrent (AC). For example, battery 108 may be configured to store andoutput DC power, whereas energy grid 104 and campus 102 may beconfigured to consume and generate AC power. Power inverter 106 may beused to convert DC power from battery 108 into a sinusoidal AC outputsynchronized to the grid frequency of energy grid 104. Power inverter106 may also be used to convert AC power from campus 102 or energy grid104 into DC power that can be stored in battery 108. The power output ofbattery 108 is shown as P_(bat). P_(bat) may be positive if battery 108is providing power to power inverter 106 or negative if battery 108 isreceiving power from power inverter 106.

In some embodiments, power inverter 106 receives a DC power output frombattery 108 and converts the DC power output to an AC power output. TheAC power output can be used to satisfy the energy load of campus 102and/or can be provided to energy grid 104. Power inverter 106 maysynchronize the frequency of the AC power output with that of energygrid 104 (e.g., 50 Hz or 60 Hz) using a local oscillator and may limitthe voltage of the AC power output to no higher than the grid voltage.In some embodiments, power inverter 106 is a resonant inverter thatincludes or uses LC circuits to remove the harmonics from a simplesquare wave in order to achieve a sine wave matching the frequency ofenergy grid 104. In various embodiments, power inverter 106 may operateusing high-frequency transformers, low-frequency transformers, orwithout transformers. Low-frequency transformers may convert the DCoutput from battery 108 directly to the AC output provided to energygrid 104. High-frequency transformers may employ a multi-step processthat involves converting the DC output to high-frequency AC, then backto DC, and then finally to the AC output provided to energy grid 104.

System 100 is shown to include a point of interconnection (POI) 110. POI110 is the point at which campus 102, energy grid 104, and powerinverter 106 are electrically connected. The power supplied to POI 110from power inverter 106 is shown as P_(sup). P_(sup) may be defined asP_(bat)+P_(loss), where P_(batt) is the battery power and P_(loss) isthe power loss in the battery system (e.g., losses in power inverter 106and/or battery 108). P_(bat) and P_(sup) may be positive if powerinverter 106 is providing power to POI 110 or negative if power inverter106 is receiving power from POI 110. P_(campus) and P_(sup) combine atPOI 110 to form P_(POI). P_(POI) may be defined as the power provided toenergy grid 104 from POI 110. P_(POI) may be positive if POI 110 isproviding power to energy grid 104 or negative if POI 110 is receivingpower from energy grid 104.

Still referring to FIG. 1, system 100 is shown to include a frequencyresponse controller 112. Controller 112 may be configured to generateand provide power setpoints to power inverter 106. Power inverter 106may use the power setpoints to control the amount of power P_(sup)provided to POI 110 or drawn from POI 110. For example, power inverter106 may be configured to draw power from POI 110 and store the power inbattery 108 in response to receiving a negative power setpoint fromcontroller 112. Conversely, power inverter 106 may be configured to drawpower from battery 108 and provide the power to POI 110 in response toreceiving a positive power setpoint from controller 112. The magnitudeof the power setpoint may define the amount of power P_(sup) provided toor from power inverter 106. Controller 112 may be configured to generateand provide power setpoints that optimize the value of operating system100 over a time horizon.

In some embodiments, frequency response controller 112 uses powerinverter 106 and battery 108 to perform frequency regulation for energygrid 104. Frequency regulation is the process of maintaining thestability of the grid frequency (e.g., 60 Hz in the United States). Thegrid frequency may remain stable and balanced as long as the totalelectric supply and demand of energy grid 104 are balanced. Anydeviation from that balance may result in a deviation of the gridfrequency from its desirable value. For example, an increase in demandmay cause the grid frequency to decrease, whereas an increase in supplymay cause the grid frequency to increase. Frequency response controller112 may be configured to offset a fluctuation in the grid frequency bycausing power inverter 106 to supply energy from battery 108 to energygrid 104 (e.g., to offset a decrease in grid frequency) or store energyfrom energy grid 104 in battery 108 (e.g., to offset an increase in gridfrequency).

In some embodiments, frequency response controller 112 uses powerinverter 106 and battery 108 to perform load shifting for campus 102.For example, controller 112 may cause power inverter 106 to store energyin battery 108 when energy prices are low and retrieve energy frombattery 108 when energy prices are high in order to reduce the cost ofelectricity required to power campus 102. Load shifting may also allowsystem 100 reduce the demand charge incurred. Demand charge is anadditional charge imposed by some utility providers based on the maximumpower consumption during an applicable demand charge period. Forexample, a demand charge rate may be specified in terms of dollars perunit of power (e.g., $/kW) and may be multiplied by the peak power usage(e.g., kW) during a demand charge period to calculate the demand charge.Load shifting may allow system 100 to smooth momentary spikes in theelectric demand of campus 102 by drawing energy from battery 108 inorder to reduce peak power draw from energy grid 104, thereby decreasingthe demand charge incurred.

Still referring to FIG. 1, system 100 is shown to include an incentiveprovider 114. Incentive provider 114 may be a utility (e.g., an electricutility), a regional transmission organization (RTO), an independentsystem operator (ISO), or any other entity that provides incentives forperforming frequency regulation. For example, incentive provider 114 mayprovide system 100 with monetary incentives for participating in afrequency response program. In order to participate in the frequencyresponse program, system 100 may maintain a reserve capacity of storedenergy (e.g., in battery 108) that can be provided to energy grid 104.System 100 may also maintain the capacity to draw energy from energygrid 104 and store the energy in battery 108. Reserving both of thesecapacities may be accomplished by managing the state-of-charge ofbattery 108.

Frequency response controller 112 may provide incentive provider 114with a price bid and a capability bid. The price bid may include a priceper unit power (e.g., $/MW) for reserving or storing power that allowssystem 100 to participate in a frequency response program offered byincentive provider 114. The price per unit power bid by frequencyresponse controller 112 is referred to herein as the “capability price.”The price bid may also include a price for actual performance, referredto herein as the “performance price.” The capability bid may define anamount of power (e.g., MW) that system 100 will reserve or store inbattery 108 to perform frequency response, referred to herein as the“capability bid.”

Incentive provider 114 may provide frequency response controller 112with a capability clearing price CP_(cap), a performance clearing priceCP_(perf), and a regulation award Reg_(award), which correspond to thecapability price, the performance price, and the capability bid,respectively. In some embodiments, CP_(cap), CP_(perf), and Reg_(award)are the same as the corresponding bids placed by controller 112. Inother embodiments, CP_(cap), CP_(perf), and Reg_(award) may not be thesame as the bids placed by controller 112. For example, CP_(cap),CP_(perf), and Reg_(award) may be generated by incentive provider 114based on bids received from multiple participants in the frequencyresponse program. Controller 112 may use CP_(cap), CP_(perf), andReg_(award) to perform frequency regulation.

Frequency response controller 112 is shown receiving a regulation signalfrom incentive provider 114. The regulation signal may specify a portionof the regulation award Reg_(award) that frequency response controller112 is to add or remove from energy grid 104. In some embodiments, theregulation signal is a normalized signal (e.g., between −1 and 1)specifying a proportion of Reg_(award). Positive values of theregulation signal may indicate an amount of power to add to energy grid104, whereas negative values of the regulation signal may indicate anamount of power to remove from energy grid 104.

Frequency response controller 112 may respond to the regulation signalby generating an optimal power setpoint for power inverter 106. Theoptimal power setpoint may take into account both the potential revenuefrom participating in the frequency response program and the costs ofparticipation. Costs of participation may include, for example, amonetized cost of battery degradation as well as the energy and demandcharges that will be incurred. The optimization may be performed usingsequential quadratic programming, dynamic programming, or any otheroptimization technique.

In some embodiments, controller 112 uses a battery life model toquantify and monetize battery degradation as a function of the powersetpoints provided to power inverter 106. Advantageously, the batterylife model allows controller 112 to perform an optimization that weighsthe revenue generation potential of participating in the frequencyresponse program against the cost of battery degradation and other costsof participation (e.g., less battery power available for campus 102,increased electricity costs, etc.). An exemplary regulation signal andpower response are described in greater detail with reference to FIG. 2.

Referring now to FIG. 2, a pair of frequency response graphs 200 and 250are shown, according to an exemplary embodiment. Graph 200 illustrates aregulation signal Reg_(signal) 202 as a function of time. Reg_(signal)202 is shown as a normalized signal ranging from −1 to 1 (i.e.,−1≤Reg_(signal)≤1). Reg_(signal) 202 may be generated by incentiveprovider 114 and provided to frequency response controller 112.Reg_(signal) 202 may define a proportion of the regulation awardReg_(award) 254 that controller 112 is to add or remove from energy grid104, relative to a baseline value referred to as the midpoint b 256. Forexample, if the value of Reg_(award) 254 is 10 MW, a regulation signalvalue of 0.5 (i.e., Reg_(signal)=0.5) may indicate that system 100 isrequested to add 5 MW of power at POI 110 relative to midpoint b (e.g.,P*_(POI)=10 MW×0.5+b), whereas a regulation signal value of −0.3 mayindicate that system 100 is requested to remove 3 MW of power from POI110 relative to midpoint b (e.g., P*_(POI)=10 MW×0.3+b).

Graph 250 illustrates the desired interconnection power P*_(POI) 252 asa function of time. P*_(POI) 252 may be calculated by frequency responsecontroller 112 based on Reg_(signal) 202, Reg_(award) 254, and amidpoint b 256. For example, controller 112 may calculate P*_(POI) 252using the following equation:

P* _(POI)=Reg_(award)×Reg_(signal) +b

where P*_(POI) represents the desired power at POI 110 (e.g.,P*_(POI)=P_(sup)+P_(campus)) and b is the midpoint. Midpoint b may bedefined (e.g., set or optimized) by controller 112 and may represent themidpoint of regulation around which the load is modified in response toReg_(signal) 202. Optimal adjustment of midpoint b may allow controller112 to actively participate in the frequency response market while alsotaking into account the energy and demand charge that will be incurred.

In order to participate in the frequency response market, controller 112may perform several tasks. Controller 112 may generate a price bid(e.g., $/MW) that includes the capability price and the performanceprice. In some embodiments, controller 112 sends the price bid toincentive provider 114 at approximately 15:30 each day and the price bidremains in effect for the entirety of the next day. Prior to beginning afrequency response period, controller 112 may generate the capabilitybid (e.g., MW) and send the capability bid to incentive provider 114. Insome embodiments, controller 112 generates and sends the capability bidto incentive provider 114 approximately 1.5 hours before a frequencyresponse period begins. In an exemplary embodiment, each frequencyresponse period has a duration of one hour; however, it is contemplatedthat frequency response periods may have any duration.

At the start of each frequency response period, controller 112 maygenerate the midpoint b around which controller 112 plans to performfrequency regulation. In some embodiments, controller 112 generates amidpoint b that will maintain battery 108 at a constant state-of-charge(SOC) (i.e. a midpoint that will result in battery 108 having the sameSOC at the beginning and end of the frequency response period). In otherembodiments, controller 112 generates midpoint b using an optimizationprocedure that allows the SOC of battery 108 to have different values atthe beginning and end of the frequency response period. For example,controller 112 may use the SOC of battery 108 as a constrained variablethat depends on midpoint b in order to optimize a value function thattakes into account frequency response revenue, energy costs, and thecost of battery degradation. Exemplary techniques for calculating and/oroptimizing midpoint b under both the constant SOC scenario and thevariable SOC scenario are described in detail in U.S. patent applicationSer. No. 15/247,883 filed Aug. 25, 2016, U.S. patent application Ser.No. 15/247,885 filed Aug. 25, 2016, and U.S. patent application Ser. No.15/247,886 filed Aug. 25, 2016. The entire disclosure of each of thesepatent applications is incorporated by reference herein.

During each frequency response period, controller 112 may periodicallygenerate a power setpoint for power inverter 106. For example,controller 112 may generate a power setpoint for each time step in thefrequency response period. In some embodiments, controller 112 generatesthe power setpoints using the equation:

P* _(POI)=Reg_(award)×Reg_(signal) +b

where P*_(POI)=P_(sup)+P_(campus). Positive values of P*_(POI) indicateenergy flow from POI 110 to energy grid 104. Positive values of P_(sup)and P_(campus) indicate energy flow to POI 110 from power inverter 106and campus 102, respectively.

In other embodiments, controller 112 generates the power setpoints usingthe equation:

P* _(POI)=Reg_(award)×Res_(FR) +b

where Res_(FR) is an optimal frequency response generated by optimizinga value function. Controller 112 may subtract P_(campus) from P*_(POI)to generate the power setpoint for power inverter 106 (i.e.,P_(sup)=P*_(POI)−P_(campus)). The power setpoint for power inverter 106indicates the amount of power that power inverter 106 is to add to POI110 (if the power setpoint is positive) or remove from POI 110 (if thepower setpoint is negative). Exemplary techniques which can be used bycontroller 112 to calculate power inverter setpoints are described indetail in U.S. patent application Ser. No. 15/247,793 filed Aug. 25,2016, U.S. patent application Ser. No. 15/247,784 filed Aug. 25, 2016,and U.S. patent application Ser. No. 15/247,777 filed Aug. 25, 2016. Theentire disclosure of each of these patent applications is incorporatedby reference herein.Photovoltaic Energy System with Frequency Regulation and Ramp RateControl

Referring now to FIGS. 3-4, a photovoltaic energy system 300 that usesbattery storage to simultaneously perform both ramp rate control andfrequency regulation is shown, according to an exemplary embodiment.Ramp rate control is the process of offsetting ramp rates (i.e.,increases or decreases in the power output of an energy system such as aphotovoltaic energy system) that fall outside of compliance limitsdetermined by the electric power authority overseeing the energy grid.Ramp rate control typically requires the use of an energy source thatallows for offsetting ramp rates by either supplying additional power tothe grid or consuming more power from the grid. In some instances, afacility is penalized for failing to comply with ramp rate requirements.

Frequency regulation is the process of maintaining the stability of thegrid frequency (e.g., 60 Hz in the United States). As shown in FIG. 4,the grid frequency may remain balanced at 60 Hz as long as there is abalance between the demand from the energy grid and the supply to theenergy grid. An increase in demand yields a decrease in grid frequency,whereas an increase in supply yields an increase in grid frequency.During a fluctuation of the grid frequency, system 300 may offset thefluctuation by either drawing more energy from the energy grid (e.g., ifthe grid frequency is too high) or by providing energy to the energygrid (e.g., if the grid frequency is too low). Advantageously, system300 may use battery storage in combination with photovoltaic power toperform frequency regulation while simultaneously complying with ramprate requirements and maintaining the state-of-charge of the batterystorage within a predetermined desirable range.

Referring particularly to FIG. 3, system 300 is shown to include aphotovoltaic (PV) field 302, a PV field power inverter 304, a battery306, a battery power inverter 308, a point of interconnection (POI) 310,and an energy grid 312. PV field 302 may include a collection ofphotovoltaic cells. The photovoltaic cells are configured to convertsolar energy (i.e., sunlight) into electricity using a photovoltaicmaterial such as monocrystalline silicon, polycrystalline silicon,amorphous silicon, cadmium telluride, copper indium galliumselenide/sulfide, or other materials that exhibit the photovoltaiceffect. In some embodiments, the photovoltaic cells are contained withinpackaged assemblies that form solar panels. Each solar panel may includea plurality of linked photovoltaic cells. The solar panels may combineto form a photovoltaic array.

PV field 302 may have any of a variety of sizes and/or locations. Insome embodiments, PV field 302 is part of a large-scale photovoltaicpower station (e.g., a solar park or farm) capable of providing anenergy supply to a large number of consumers. When implemented as partof a large-scale system, PV field 302 may cover multiple hectares andmay have power outputs of tens or hundreds of megawatts. In otherembodiments, PV field 302 may cover a smaller area and may have arelatively lesser power output (e.g., between one and ten megawatts,less than one megawatt, etc.). For example, PV field 302 may be part ofa rooftop-mounted system capable of providing enough electricity topower a single home or building. It is contemplated that PV field 302may have any size, scale, and/or power output, as may be desirable indifferent implementations.

PV field 302 may generate a direct current (DC) output that depends onthe intensity and/or directness of the sunlight to which the solarpanels are exposed. The directness of the sunlight may depend on theangle of incidence of the sunlight relative to the surfaces of the solarpanels. The intensity of the sunlight may be affected by a variety ofenvironmental factors such as the time of day (e.g., sunrises andsunsets) and weather variables such as clouds that cast shadows upon PVfield 302. When PV field 302 is partially or completely covered byshadow, the power output of PV field 302 (i.e., PV field power P_(PV))may drop as a result of the decrease in solar intensity.

In some embodiments, PV field 302 is configured to maximize solar energycollection. For example, PV field 302 may include a solar tracker (e.g.,a GPS tracker, a sunlight sensor, etc.) that adjusts the angle of thesolar panels so that the solar panels are aimed directly at the sunthroughout the day. The solar tracker may allow the solar panels toreceive direct sunlight for a greater portion of the day and mayincrease the total amount of power produced by PV field 302. In someembodiments, PV field 302 includes a collection of mirrors, lenses, orsolar concentrators configured to direct and/or concentrate sunlight onthe solar panels. The energy generated by PV field 302 may be stored inbattery 306 or provided to energy grid 312.

Still referring to FIG. 3, system 300 is shown to include a PV fieldpower inverter 304. Power inverter 304 may be configured to convert theDC output of PV field 302 P_(PV) into an alternating current (AC) outputthat can be fed into energy grid 312 or used by a local (e.g., off-grid)electrical network. For example, power inverter 304 may be a solarinverter or grid-tie inverter configured to convert the DC output fromPV field 302 into a sinusoidal AC output synchronized to the gridfrequency of energy grid 312. In some embodiments, power inverter 304receives a cumulative DC output from PV field 302. For example, powerinverter 304 may be a string inverter or a central inverter. In otherembodiments, power inverter 304 may include a collection ofmicro-inverters connected to each solar panel or solar cell. PV fieldpower inverter 304 may convert the DC power output P_(PV) into an ACpower output u_(PV) and provide the AC power output u_(PV) to POI 310.

Power inverter 304 may receive the DC power output P_(PV) from PV field302 and convert the DC power output to an AC power output that can befed into energy grid 312. Power inverter 304 may synchronize thefrequency of the AC power output with that of energy grid 312 (e.g., 50Hz or 60 Hz) using a local oscillator and may limit the voltage of theAC power output to no higher than the grid voltage. In some embodiments,power inverter 304 is a resonant inverter that includes or uses LCcircuits to remove the harmonics from a simple square wave in order toachieve a sine wave matching the frequency of energy grid 312. Invarious embodiments, power inverter 304 may operate using high-frequencytransformers, low-frequency transformers, or without transformers.Low-frequency transformers may convert the DC output from PV field 302directly to the AC output provided to energy grid 312. High-frequencytransformers may employ a multi-step process that involves convertingthe DC output to high-frequency AC, then back to DC, and then finally tothe AC output provided to energy grid 312.

Power inverter 304 may be configured to perform maximum power pointtracking and/or anti-islanding. Maximum power point tracking may allowpower inverter 304 to produce the maximum possible AC power from PVfield 302. For example, power inverter 304 may sample the DC poweroutput from PV field 302 and apply a variable resistance to find theoptimum maximum power point. Anti-islanding is a protection mechanismthat immediately shuts down power inverter 304 (i.e., preventing powerinverter 304 from generating AC power) when the connection to anelectricity-consuming load no longer exists. In some embodiments, PVfield power inverter 304 performs ramp rate control by limiting thepower generated by PV field 302.

Still referring to FIG. 3, system 300 is shown to include a batterypower inverter 308. Battery power inverter 308 may be configured to drawa DC power P_(bat) from battery 306, convert the DC power P_(bat) intoan AC power u_(bat), and provide the AC power u_(bat) to POI 310.Battery power inverter 308 may also be configured to draw the AC poweru_(bat) from POI 310, convert the AC power u_(bat) into a DC batterypower P_(bat), and store the DC battery power P_(bat) in battery 306.The DC battery power P_(bat) may be positive if battery 306 is providingpower to battery power inverter 308 (i.e., if battery 306 isdischarging) or negative if battery 306 is receiving power from batterypower inverter 308 (i.e., if battery 306 is charging). Similarly, the ACbattery power u_(bat) may be positive if battery power inverter 308 isproviding power to POI 310 or negative if battery power inverter 308 isreceiving power from POI 310.

The AC battery power u_(bat) is shown to include an amount of power usedfor frequency regulation (i.e., u_(RR)) and an amount of power used forramp rate control (i.e., u_(RR)) which together form the AC batterypower (i.e., u_(bat)=u_(FR)+u_(RR)). The DC battery power P_(bat) isshown to include both u_(RR) and u_(RR) as well as an additional termP_(loss) representing power losses in battery 306 and/or battery powerinverter 308 (i.e., P_(bat)=u_(FR)+u_(RR)+P_(loss)). The PV field poweru_(PV) and the battery power u_(bat) combine at POI 110 to form P_(POI)(i.e., P_(POI)=u_(PV) u_(bat)), which represents the amount of powerprovided to energy grid 312. P_(POI) may be positive if POI 310 isproviding power to energy grid 312 or negative if POI 310 is receivingpower from energy grid 312.

Still referring to FIG. 3, system 300 is shown to include a controller314. Controller 314 may be configured to generate a PV power setpointu_(PV) for PV field power inverter 304 and a battery power setpointu_(bat) for battery power inverter 308. Throughout this disclosure, thevariable u_(PV) is used to refer to both the PV power setpoint generatedby controller 314 and the AC power output of PV field power inverter 304since both quantities have the same value. Similarly, the variableu_(bat) is used to refer to both the battery power setpoint generated bycontroller 314 and the AC power output/input of battery power inverter308 since both quantities have the same value.

PV field power inverter 304 uses the PV power setpoint u_(PV) to controlan amount of the PV field power P_(PV) to provide to POI 110. Themagnitude of u_(PV) may be the same as the magnitude of P_(PV) or lessthan the magnitude of P_(PV). For example, u_(PV) may be the same asP_(PV) if controller 314 determines that PV field power inverter 304 isto provide all of the photovoltaic power P_(PV) to POI 310. However,u_(PV) may be less than P_(PV) if controller 314 determines that PVfield power inverter 304 is to provide less than all of the photovoltaicpower P_(PV) to POI 310. For example, controller 314 may determine thatit is desirable for PV field power inverter 304 to provide less than allof the photovoltaic power P_(PV) to POI 310 to prevent the ramp ratefrom being exceeded and/or to prevent the power at POI 310 fromexceeding a power limit.

Battery power inverter 308 uses the battery power setpoint u_(bat) tocontrol an amount of power charged or discharged by battery 306. Thebattery power setpoint u_(bat) may be positive if controller 314determines that battery power inverter 308 is to draw power from battery306 or negative if controller 314 determines that battery power inverter308 is to store power in battery 306. The magnitude of u_(bat) controlsthe rate at which energy is charged or discharged by battery 306.

Controller 314 may generate u_(PV) and u_(bat) based on a variety ofdifferent variables including, for example, a power signal from PV field302 (e.g., current and previous values for P_(PV)), the currentstate-of-charge (SOC) of battery 306, a maximum battery power limit, amaximum power limit at POI 310, the ramp rate limit, the grid frequencyof energy grid 312, and/or other variables that can be used bycontroller 314 to perform ramp rate control and/or frequency regulation.Advantageously, controller 314 generates values for u_(PV) and u_(bat)that maintain the ramp rate of the PV power within the ramp ratecompliance limit while participating in the regulation of grid frequencyand maintaining the SOC of battery 306 within a predetermined desirablerange.

An exemplary controller which can be used as controller 314 andexemplary processes which may be performed by controller 314 to generatethe PV power setpoint u_(PV) and the battery power setpoint u_(bat) aredescribed in detail in U.S. patent application Ser. No. 15/247,869 filedAug. 25, 2016, U.S. patent application Ser. No. 15/247,844 filed Aug.25, 2016, U.S. patent application Ser. No. 15/247,788 filed Aug. 25,2016, U.S. patent application Ser. No. 15/247,872 filed Aug. 25, 2016,U.S. patent application Ser. No. 15/247,880 filed Aug. 25, 2016, andU.S. patent application Ser. No. 15/247,873 filed Aug. 25, 2016. Theentire disclosure of each of these patent applications is incorporatedby reference herein.

Energy Storage System with Thermal and Electrical Energy Storage

Referring now to FIG. 5A, a block diagram of an energy storage system500 is shown, according to an exemplary embodiment. Energy storagesystem 500 is shown to include a building 502. Building 502 may be thesame or similar to buildings 116, as described with reference to FIG. 1.For example, building 502 may be equipped with a HVAC system and/or abuilding management system that operates to control conditions withinbuilding 502. In some embodiments, building 502 includes multiplebuildings (i.e., a campus) served by energy storage system 500. Building502 may demand various resources including, for example, hot thermalenergy (e.g., hot water), cold thermal energy (e.g., cold water), and/orelectrical energy. The resources may be demanded by equipment orsubsystems within building 502 or by external systems that provideservices for building 502 (e.g., heating, cooling, air circulation,lighting, electricity, etc.). Energy storage system 500 operates tosatisfy the resource demand associated with building 502.

Energy storage system 500 is shown to include a plurality of utilities510. Utilities 510 may provide energy storage system 500 with resourcessuch as electricity, water, natural gas, or any other resource that canbe used by energy storage system 500 to satisfy the demand of building502. For example, utilities 510 are shown to include an electric utility511, a water utility 512, a natural gas utility 513, and utility M 514,where M is the total number of utilities 510. In some embodiments,utilities 510 are commodity suppliers from which resources and othertypes of commodities can be purchased. Resources purchased fromutilities 510 can be used by generator subplants 520 to producegenerated resources (e.g., hot water, cold water, electricity, steam,etc.), stored in storage subplants 530 for later use, or provideddirectly to building 502. For example, utilities 510 are shown providingelectricity directly to building 502 and storage subplants 530.

Energy storage system 500 is shown to include a plurality of generatorsubplants 520. In some embodiments, generator subplants 520 arecomponents of a central plant (e.g., central plant 118). Generatorsubplants 520 are shown to include a heater subplant 521, a chillersubplant 522, a heat recovery chiller subplant 523, a steam subplant524, an electricity subplant 525, and subplant N, where N is the totalnumber of generator subplants 520. Generator subplants 520 may beconfigured to convert one or more input resources into one or moreoutput resources by operation of the equipment within generatorsubplants 520. For example, heater subplant 521 may be configured togenerate hot thermal energy (e.g., hot water) by heating water usingelectricity or natural gas. Chiller subplant 522 may be configured togenerate cold thermal energy (e.g., cold water) by chilling water usingelectricity. Heat recovery chiller subplant 523 may be configured togenerate hot thermal energy and cold thermal energy by removing heatfrom one water supply and adding the heat to another water supply. Steamsubplant 524 may be configured to generate steam by boiling water usingelectricity or natural gas. Electricity subplant 525 may be configuredto generate electricity using mechanical generators (e.g., a steamturbine, a gas-powered generator, etc.) or other types ofelectricity-generating equipment (e.g., photovoltaic equipment,hydroelectric equipment, etc.).

The input resources used by generator subplants 520 may be provided byutilities 510, retrieved from storage subplants 530, and/or generated byother generator subplants 520. For example, steam subplant 524 mayproduce steam as an output resource. Electricity subplant 525 mayinclude a steam turbine that uses the steam generated by steam subplant524 as an input resource to generate electricity. The output resourcesproduced by generator subplants 520 may be stored in storage subplants530, provided to building 502, sold to energy purchasers 504, and/orused by other generator subplants 520. For example, the electricitygenerated by electricity subplant 525 may be stored in electrical energystorage 533, used by chiller subplant 522 to generate cold thermalenergy, provided to building 502, and/or sold to energy purchasers 504.

Energy storage system 500 is shown to include storage subplants 530. Insome embodiments, storage subplants 530 are components of a centralplant (e.g., central plant 118). Storage subplants 530 may be configuredto store energy and other types of resources for later use. Each ofstorage subplants 530 may be configured to store a different type ofresource. For example, storage subplants 530 are shown to include hotthermal energy storage 531 (e.g., one or more hot water storage tanks),cold thermal energy storage 532 (e.g., one or more cold thermal energystorage tanks), electrical energy storage 533 (e.g., one or morebatteries), and resource type P storage 534, where P is the total numberof storage subplants 530. The resources stored in subplants 530 may bepurchased directly from utilities 510 or generated by generatorsubplants 520.

In some embodiments, storage subplants 530 are used by energy storagesystem 500 to take advantage of price-based demand response (PBDR)programs. PBDR programs encourage consumers to reduce consumption whengeneration, transmission, and distribution costs are high. PBDR programsare typically implemented (e.g., by utilities 510) in the form of energyprices that vary as a function of time. For example, utilities 510 mayincrease the price per unit of electricity during peak usage hours toencourage customers to reduce electricity consumption during peak times.Some utilities also charge consumers a separate demand charge based onthe maximum rate of electricity consumption at any time during apredetermined demand charge period.

Advantageously, storing energy and other types of resources in subplants530 allows for the resources to be purchased at times when the resourcesare relatively less expensive (e.g., during non-peak electricity hours)and stored for use at times when the resources are relatively moreexpensive (e.g., during peak electricity hours). Storing resources insubplants 530 also allows the resource demand of building 502 to beshifted in time. For example, resources can be purchased from utilities510 at times when the demand for heating or cooling is low andimmediately converted into hot or cold thermal energy by generatorsubplants 520. The thermal energy can be stored in storage subplants 530and retrieved at times when the demand for heating or cooling is high.This allows energy storage system 500 to smooth the resource demand ofbuilding 502 and reduces the maximum required capacity of generatorsubplants 520. Smoothing the demand also allows energy storage system500 to reduce the peak electricity consumption, which results in a lowerdemand charge.

In some embodiments, storage subplants 530 are used by energy storagesystem 500 to take advantage of incentive-based demand response (IBDR)programs. IBDR programs provide incentives to customers who have thecapability to store energy, generate energy, or curtail energy usageupon request. Incentives are typically provided in the form of monetaryrevenue paid by utilities 510 or by an independent service operator(ISO). IBDR programs supplement traditional utility-owned generation,transmission, and distribution assets with additional options formodifying demand load curves. For example, stored energy can be sold toenergy purchasers 504 (e.g., an energy grid) to supplement the energygenerated by utilities 510. In some instances, incentives forparticipating in an IBDR program vary based on how quickly a system canrespond to a request to change power output/consumption. Fasterresponses may be compensated at a higher level. Advantageously,electrical energy storage 533 allows system 500 to quickly respond to arequest for electric power by rapidly discharging stored electricalenergy to energy purchasers 504.

Still referring to FIG. 5A, energy storage system 500 is shown toinclude an energy storage controller 506. Energy storage controller 506may be configured to control the distribution, production, storage, andusage of resources in energy storage system 500. In some embodiments,energy storage controller 506 performs an optimization process determinean optimal set of control decisions for each time step within anoptimization period. The control decisions may include, for example, anoptimal amount of each resource to purchase from utilities 510, anoptimal amount of each resource to produce or convert using generatorsubplants 520, an optimal amount of each resource to store or removefrom storage subplants 530, an optimal amount of each resource to sellto energy purchasers 504, and/or an optimal amount of each resource toprovide to building 502. In some embodiments, the control decisionsinclude an optimal amount of each input resource and output resource foreach of generator subplants 520.

Controller 506 may be configured to maximize the economic value ofoperating energy storage system 500 over the duration of theoptimization period. The economic value may be defined by a valuefunction that expresses economic value as a function of the controldecisions made by controller 506. The value function may account for thecost of resources purchased from utilities 510, revenue generated byselling resources to energy purchasers 504, and the cost of operatingenergy storage system 500. In some embodiments, the cost of operatingenergy storage system 500 includes a cost for losses in battery capacityas a result of the charging and discharging electrical energy storage533. The cost of operating energy storage system 500 may also include acost of excessive equipment start/stops during the optimization period.

Each of subplants 520-530 may include equipment that can be controlledby energy storage controller 506 to optimize the performance of energystorage system 500. Subplant equipment may include, for example, heatingdevices, chillers, heat recovery heat exchangers, cooling towers, energystorage devices, pumps, valves, and/or other devices of subplants520-530. Individual devices of generator subplants 520 can be turned onor off to adjust the resource production of each generator subplant. Insome embodiments, individual devices of generator subplants 520 can beoperated at variable capacities (e.g., operating a chiller at 10%capacity or 60% capacity) according to an operating setpoint receivedfrom energy storage controller 506.

In some embodiments, one or more of subplants 520-530 includes asubplant level controller configured to control the equipment of thecorresponding subplant. For example, energy storage controller 506 maydetermine an on/off configuration and global operating setpoints for thesubplant equipment. In response to the on/off configuration and receivedglobal operating setpoints, the subplant controllers may turn individualdevices of their respective equipment on or off, and implement specificoperating setpoints (e.g., damper position, vane position, fan speed,pump speed, etc.) to reach or maintain the global operating setpoints.

In some embodiments, controller 506 maximizes the life cycle economicvalue of energy storage system 500 while participating in PBDR programs,IBDR programs, or simultaneously in both PBDR and IBDR programs. For theIBDR programs, controller 506 may use statistical estimates of pastclearing prices, mileage ratios, and event probabilities to determinethe revenue generation potential of selling stored energy to energypurchasers 504. For the PBDR programs, controller 506 may usepredictions of ambient conditions, facility thermal loads, andthermodynamic models of installed equipment to estimate the resourceconsumption of subplants 520. Controller 506 may use predictions of theresource consumption to monetize the costs of running the equipment.

Controller 506 may automatically determine (e.g., without humanintervention) a combination of PBDR and/or IBDR programs in which toparticipate over the optimization period in order to maximize economicvalue. For example, controller 506 may consider the revenue generationpotential of IBDR programs, the cost reduction potential of PBDRprograms, and the equipment maintenance/replacement costs that wouldresult from participating in various combinations of the IBDR programsand PBDR programs. Controller 506 may weigh the benefits ofparticipation against the costs of participation to determine an optimalcombination of programs in which to participate. Advantageously, thisallows controller 506 to determine an optimal set of control decisionsthat maximize the overall value of operating energy storage system 500.

In some instances, controller 506 may determine that it would bebeneficial to participate in an IBDR program when the revenue generationpotential is high and/or the costs of participating are low. Forexample, controller 506 may receive notice of a synchronous reserveevent from an IBDR program which requires energy storage system 500 toshed a predetermined amount of power. Controller 506 may determine thatit is optimal to participate in the IBDR program if cold thermal energystorage 532 has enough capacity to provide cooling for building 502while the load on chiller subplant 522 is reduced in order to shed thepredetermined amount of power.

In other instances, controller 506 may determine that it would not bebeneficial to participate in an IBDR program when the resources requiredto participate are better allocated elsewhere. For example, if building502 is close to setting a new peak demand that would greatly increasethe PBDR costs, controller 506 may determine that only a small portionof the electrical energy stored in electrical energy storage 533 will besold to energy purchasers 504 in order to participate in a frequencyresponse market. Controller 506 may determine that the remainder of theelectrical energy will be used to power chiller subplant 522 to preventa new peak demand from being set.

In some embodiments, energy storage system 500 and controller includesome or all of the components and/or features described in U.S. patentapplication Ser. No. 15/247,875 filed Aug. 25, 2016, U.S. patentapplication Ser. No. 15/247,879 filed Aug. 25, 2016, and U.S. patentapplication Ser. No. 15/247,881 filed Aug. 25, 2016. The entiredisclosure of each of these patent applications is incorporated byreference herein.

Energy Cost Optimization System

Referring now to FIG. 5B, a block diagram of an energy cost optimizationsystem 550 is shown, according to an exemplary embodiment. Energy costoptimization system 550 is shown to include many of the same componentsas energy storage system 500 (described with reference to FIG. 5A) withthe exception of storage subplants 530. System 550 is an example of asystem without thermal or electrical energy storage in which the peakload contribution cost optimization techniques can be implemented.

Energy cost optimization system 550 is shown to include a building 502.Building 502 may be the same or similar to buildings 116, as describedwith reference to FIG. 1. For example, building 502 may be equipped witha HVAC system and/or a building management system that operates tocontrol conditions within building 502. In some embodiments, building502 includes multiple buildings (i.e., a campus) served by energy costoptimization system 550. Building 502 may demand various resourcesincluding, for example, hot thermal energy (e.g., hot water), coldthermal energy (e.g., cold water), and/or electrical energy. Theresources may be demanded by equipment or subsystems within building 502or by external systems that provide services for building 502 (e.g.,heating, cooling, air circulation, lighting, electricity, etc.). Energycost optimization system 550 operates to satisfy the resource demandassociated with building 502.

Energy cost optimization system 550 is shown to include a plurality ofutilities 510. Utilities 510 may provide system 550 with resources suchas electricity, water, natural gas, or any other resource that can beused by system 550 to satisfy the demand of building 502. For example,utilities 510 are shown to include an electric utility 511, a waterutility 512, a natural gas utility 513, and utility M 514, where M isthe total number of utilities 510. In some embodiments, utilities 510are commodity suppliers from which resources and other types ofcommodities can be purchased. Resources purchased from utilities 510 canbe used by generator subplants 520 to produce generated resources (e.g.,hot water, cold water, electricity, steam, etc.) or provided directly tobuilding 502. For example, utilities 510 are shown providing electricitydirectly to building 502.

Energy cost optimization system 550 is shown to include a plurality ofgenerator subplants 520. Generator subplants 520 are shown to include aheater subplant 521, a chiller subplant 522, a heat recovery chillersubplant 523, a steam subplant 524, an electricity subplant 525, andsubplant N, where N is the total number of generator subplants 520.Generator subplants 520 may be configured to convert one or more inputresources into one or more output resources by operation of theequipment within generator subplants 520. For example, heater subplant521 may be configured to generate hot thermal energy (e.g., hot water)by heating water using electricity or natural gas. Chiller subplant 522may be configured to generate cold thermal energy (e.g., cold water) bychilling water using electricity. Heat recovery chiller subplant 523 maybe configured to generate hot thermal energy and cold thermal energy byremoving heat from one water supply and adding the heat to another watersupply. Steam subplant 524 may be configured to generate steam byboiling water using electricity or natural gas. Electricity subplant 525may be configured to generate electricity using mechanical generators(e.g., a steam turbine, a gas-powered generator, etc.) or other types ofelectricity-generating equipment (e.g., photovoltaic equipment,hydroelectric equipment, etc.).

The input resources used by generator subplants 520 may be provided byutilities 510 and/or generated by other generator subplants 520. Forexample, steam subplant 524 may produce steam as an output resource.Electricity subplant 525 may include a steam turbine that uses the steamgenerated by steam subplant 524 as an input resource to generateelectricity. The output resources produced by generator subplants 520may be provided to building 502, sold to energy purchasers 504, and/orused by other generator subplants 520. For example, the electricitygenerated by electricity subplant 525 may be used by chiller subplant522 to generate cold thermal energy, provided to building 502, and/orsold to energy purchasers 504.

Still referring to FIG. 5B, energy cost optimization system 550 is shownto include a controller 1000. Controller 1000 may be configured tocontrol the distribution, production, and usage of resources in system550. In some embodiments, controller 1000 performs an optimizationprocess determine an optimal set of control decisions for each time stepwithin an optimization period. The control decisions may include, forexample, an optimal amount of each resource to purchase from utilities510, an optimal amount of each resource to produce or convert usinggenerator subplants 520, an optimal amount of each resource to sell toenergy purchasers 504, and/or an optimal amount of each resource toprovide to building 502. In some embodiments, the control decisionsinclude an optimal amount of each input resource and output resource foreach of generator subplants 520.

Controller 1000 may be configured to maximize the economic value ofoperating energy cost optimization system 550 over the duration of theoptimization period. The economic value may be defined by a valuefunction that expresses economic value as a function of the controldecisions made by controller 1000. The value function may account forthe cost of resources purchased from utilities 510, revenue generated byselling resources to energy purchasers 504, and the cost of operatingsystem 550. In some embodiments, the cost of operating system 550includes a cost of excessive equipment start/stops during theoptimization period.

Each of subplants 520 may include equipment that can be controlled bycontroller 1000 to optimize the performance of system 550. Subplantequipment may include, for example, heating devices, chillers, heatrecovery heat exchangers, cooling towers, pumps, valves, and/or otherdevices of subplants 520. Individual devices of generator subplants 520can be turned on or off to adjust the resource production of eachgenerator subplant. In some embodiments, individual devices of generatorsubplants 520 can be operated at variable capacities (e.g., operating achiller at 10% capacity or 60% capacity) according to an operatingsetpoint received from controller 552.

In some embodiments, one or more of subplants 520 includes a subplantlevel controller configured to control the equipment of thecorresponding subplant. For example, controller 552 may determine anon/off configuration and global operating setpoints for the subplantequipment. In response to the on/off configuration and received globaloperating setpoints, the subplant controllers may turn individualdevices of their respective equipment on or off, and implement specificoperating setpoints (e.g., damper position, vane position, fan speed,pump speed, etc.) to reach or maintain the global operating setpoints.

In some embodiments, energy cost optimization system 550 and controller552 include some or all of the components and/or features described inU.S. patent application Ser. No. 15/247,875 filed Aug. 25, 2016, U.S.patent application Ser. No. 15/247,879 filed Aug. 25, 2016, and U.S.patent application Ser. No. 15/247,881 filed Aug. 25, 2016. The entiredisclosure of each of these patent applications is incorporated byreference herein.

Energy Storage Controller

Referring now to FIG. 6A, a block diagram illustrating energy storagecontroller 506 in greater detail is shown, according to an exemplaryembodiment. Energy storage controller 506 is shown providing controldecisions to a building management system (BMS) 606. In someembodiments, BMS 606 is the same or similar the BMS described withreference to FIG. 1. The control decisions provided to BMS 606 mayinclude resource purchase amounts for utilities 510, setpoints forgenerator subplants 520, and/or charge/discharge rates for storagesubplants 530.

BMS 606 may be configured to monitor conditions within a controlledbuilding or building zone. For example, BMS 606 may receive input fromvarious sensors (e.g., temperature sensors, humidity sensors, airflowsensors, voltage sensors, etc.) distributed throughout the building andmay report building conditions to energy storage controller 506.Building conditions may include, for example, a temperature of thebuilding or a zone of the building, a power consumption (e.g., electricload) of the building, a state of one or more actuators configured toaffect a controlled state within the building, or other types ofinformation relating to the controlled building. BMS 606 may operatesubplants 520-530 to affect the monitored conditions within the buildingand to serve the thermal energy loads of the building.

BMS 606 may receive control signals from energy storage controller 506specifying on/off states, charge/discharge rates, and/or setpoints forthe subplant equipment. BMS 606 may control the equipment (e.g., viaactuators, power relays, etc.) in accordance with the control signalsprovided by energy storage controller 506. For example, BMS 606 mayoperate the equipment using closed loop control to achieve the setpointsspecified by energy storage controller 506. In various embodiments, BMS606 may be combined with energy storage controller 506 or may be part ofa separate building management system. According to an exemplaryembodiment, BMS 606 is a METASYS® brand building management system, assold by Johnson Controls, Inc.

Energy storage controller 506 may monitor the status of the controlledbuilding using information received from BMS 606. Energy storagecontroller 506 may be configured to predict the thermal energy loads(e.g., heating loads, cooling loads, etc.) of the building for pluralityof time steps in an optimization period (e.g., using weather forecastsfrom a weather service 604). Energy storage controller 506 may alsopredict the revenue generation potential of IBDR programs using anincentive event history (e.g., past clearing prices, mileage ratios,event probabilities, etc.) from incentive programs 602. Energy storagecontroller 506 may generate control decisions that optimize the economicvalue of operating energy storage system 500 over the duration of theoptimization period subject to constraints on the optimization process(e.g., energy balance constraints, load satisfaction constraints, etc.).The optimization process performed by energy storage controller 506 isdescribed in greater detail below.

According to an exemplary embodiment, energy storage controller 506 isintegrated within a single computer (e.g., one server, one housing,etc.). In various other exemplary embodiments, energy storage controller506 can be distributed across multiple servers or computers (e.g., thatcan exist in distributed locations). In another exemplary embodiment,energy storage controller 506 may be integrated with a smart buildingmanager that manages multiple building systems and/or combined with BMS606.

Energy storage controller 506 is shown to include a communicationsinterface 636 and a processing circuit 607. Communications interface 636may include wired or wireless interfaces (e.g., jacks, antennas,transmitters, receivers, transceivers, wire terminals, etc.) forconducting data communications with various systems, devices, ornetworks. For example, communications interface 636 may include anEthernet card and port for sending and receiving data via anEthernet-based communications network and/or a WiFi transceiver forcommunicating via a wireless communications network. Communicationsinterface 636 may be configured to communicate via local area networksor wide area networks (e.g., the Internet, a building WAN, etc.) and mayuse a variety of communications protocols (e.g., BACnet, IP, LON, etc.).

Communications interface 636 may be a network interface configured tofacilitate electronic data communications between energy storagecontroller 506 and various external systems or devices (e.g., BMS 606,subplants 520-530, utilities 510, etc.). For example, energy storagecontroller 506 may receive information from BMS 606 indicating one ormore measured states of the controlled building (e.g., temperature,humidity, electric loads, etc.) and one or more states of subplants520-530 (e.g., equipment status, power consumption, equipmentavailability, etc.). Communications interface 636 may receive inputsfrom BMS 606 and/or subplants 520-530 and may provide operatingparameters (e.g., on/off decisions, setpoints, etc.) to subplants520-530 via BMS 606. The operating parameters may cause subplants520-530 to activate, deactivate, or adjust a setpoint for variousdevices thereof.

Still referring to FIG. 6A, processing circuit 607 is shown to include aprocessor 608 and memory 610. Processor 608 may be a general purpose orspecific purpose processor, an application specific integrated circuit(ASIC), one or more field programmable gate arrays (FPGAs), a group ofprocessing components, or other suitable processing components.Processor 608 may be configured to execute computer code or instructionsstored in memory 610 or received from other computer readable media(e.g., CDROM, network storage, a remote server, etc.).

Memory 610 may include one or more devices (e.g., memory units, memorydevices, storage devices, etc.) for storing data and/or computer codefor completing and/or facilitating the various processes described inthe present disclosure. Memory 610 may include random access memory(RAM), read-only memory (ROM), hard drive storage, temporary storage,non-volatile memory, flash memory, optical memory, or any other suitablememory for storing software objects and/or computer instructions. Memory610 may include database components, object code components, scriptcomponents, or any other type of information structure for supportingthe various activities and information structures described in thepresent disclosure. Memory 610 may be communicably connected toprocessor 608 via processing circuit 607 and may include computer codefor executing (e.g., by processor 608) one or more processes describedherein.

Memory 610 is shown to include a building status monitor 624. Energystorage controller 506 may receive data regarding the overall buildingor building space to be heated or cooled by system 500 via buildingstatus monitor 624. In an exemplary embodiment, building status monitor624 may include a graphical user interface component configured toprovide graphical user interfaces to a user for selecting buildingrequirements (e.g., overall temperature parameters, selecting schedulesfor the building, selecting different temperature levels for differentbuilding zones, etc.).

Energy storage controller 506 may determine on/off configurations andoperating setpoints to satisfy the building requirements received frombuilding status monitor 624. In some embodiments, building statusmonitor 624 receives, collects, stores, and/or transmits cooling loadrequirements, building temperature setpoints, occupancy data, weatherdata, energy data, schedule data, and other building parameters. In someembodiments, building status monitor 624 stores data regarding energycosts, such as pricing information available from utilities 510 (energycharge, demand charge, etc.).

Still referring to FIG. 6A, memory 610 is shown to include a load/ratepredictor 622. Load/rate predictor 622 may be configured to predict thethermal energy loads (

_(k)) of the building or campus for each time step k (e.g., k=1 . . . n)of an optimization period. Load/rate predictor 622 is shown receivingweather forecasts from a weather service 604. In some embodiments,load/rate predictor 622 predicts the thermal energy loads

_(k) as a function of the weather forecasts. In some embodiments,load/rate predictor 622 uses feedback from BMS 606 to predict loads

_(k). Feedback from BMS 606 may include various types of sensory inputs(e.g., temperature, flow, humidity, enthalpy, etc.) or other datarelating to the controlled building (e.g., inputs from a HVAC system, alighting control system, a security system, a water system, etc.).

In some embodiments, load/rate predictor 622 receives a measuredelectric load and/or previous measured load data from BMS 606 (e.g., viabuilding status monitor 624). Load/rate predictor 622 may predict loads

_(k) as a function of a given weather forecast (ϕ _(w)), a day type(day), the time of day (t), and previous measured load data (Y_(k−1)).Such a relationship is expressed in the following equation:

_(k) =f({circumflex over (ϕ)}_(w),day,t|Y _(k−1))

In some embodiments, load/rate predictor 622 uses a deterministic plusstochastic model trained from historical load data to predict loads

_(k). Load/rate predictor 622 may use any of a variety of predictionmethods to predict loads

_(k) (e.g., linear regression for the deterministic portion and an ARmodel for the stochastic portion). Load/rate predictor 622 may predictone or more different types of loads for the building or campus. Forexample, load/rate predictor 622 may predict a hot water load

_(Hot,k) and a cold water load

_(Cold,k) for each time step k within the prediction window. In someembodiments, load/rate predictor 622 makes load/rate predictions usingthe techniques described in U.S. patent application Ser. No. 14/717,593.

Load/rate predictor 622 is shown receiving utility rates from utilities510. Utility rates may indicate a cost or price per unit of a resource(e.g., electricity, natural gas, water, etc.) provided by utilities 510at each time step k in the prediction window. In some embodiments, theutility rates are time-variable rates. For example, the price ofelectricity may be higher at certain times of day or days of the week(e.g., during high demand periods) and lower at other times of day ordays of the week (e.g., during low demand periods). The utility ratesmay define various time periods and a cost per unit of a resource duringeach time period. Utility rates may be actual rates received fromutilities 510 or predicted utility rates estimated by load/ratepredictor 622.

In some embodiments, the utility rates include demand charges for one ormore resources provided by utilities 510. A demand charge may define aseparate cost imposed by utilities 510 based on the maximum usage of aparticular resource (e.g., maximum energy consumption) during a demandcharge period. The utility rates may define various demand chargeperiods and one or more demand charges associated with each demandcharge period. In some instances, demand charge periods may overlappartially or completely with each other and/or with the predictionwindow. Advantageously, demand response optimizer 630 may be configuredto account for demand charges in the high level optimization processperformed by high level optimizer 632. Utilities 510 may be defined bytime-variable (e.g., hourly) prices, a maximum service level (e.g., amaximum rate of consumption allowed by the physical infrastructure or bycontract) and, in the case of electricity, a demand charge or a chargefor the peak rate of consumption within a certain period. Load/ratepredictor 622 may store the predicted loads

_(k) and the utility rates in memory 610 and/or provide the predictedloads

_(k) and the utility rates to demand response optimizer 630.

Still referring to FIG. 6A, memory 610 is shown to include an incentiveestimator 620. Incentive estimator 620 may be configured to estimate therevenue generation potential of participating in various incentive-baseddemand response (IBDR) programs. In some embodiments, incentiveestimator 620 receives an incentive event history from incentiveprograms 602. The incentive event history may include a history of pastIBDR events from incentive programs 602. An IBDR event may include aninvitation from incentive programs 602 to participate in an IBDR programin exchange for a monetary incentive. The incentive event history mayindicate the times at which the past IBDR events occurred and attributesdescribing the IBDR events (e.g., clearing prices, mileage ratios,participation requirements, etc.). Incentive estimator 620 may use theincentive event history to estimate IBDR event probabilities during theoptimization period.

Incentive estimator 620 is shown providing incentive predictions todemand response optimizer 630. The incentive predictions may include theestimated IBDR probabilities, estimated participation requirements, anestimated amount of revenue from participating in the estimated IBDRevents, and/or any other attributes of the predicted IBDR events. Demandresponse optimizer 630 may use the incentive predictions along with thepredicted loads

_(k) and utility rates from load/rate predictor 622 to determine anoptimal set of control decisions for each time step within theoptimization period.

Still referring to FIG. 6A, memory 610 is shown to include a demandresponse optimizer 630. Demand response optimizer 630 may perform acascaded optimization process to optimize the performance of energystorage system 500. For example, demand response optimizer 630 is shownto include a high level optimizer 632 and a low level optimizer 634.High level optimizer 632 may control an outer (e.g., subplant level)loop of the cascaded optimization. High level optimizer 632 maydetermine an optimal set of control decisions for each time step in theprediction window in order to optimize (e.g., maximize) the value ofoperating energy storage system 500. Control decisions made by highlevel optimizer 632 may include, for example, load setpoints for each ofgenerator subplants 520, charge/discharge rates for each of storagesubplants 530, resource purchase amounts for each type of resourcepurchased from utilities 510, and/or an amount of each resource sold toenergy purchasers 504. In other words, the control decisions may defineresource allocation at each time step. The control decisions made byhigh level optimizer 632 are based on the statistical estimates ofincentive event probabilities and revenue generation potential forvarious IBDR events as well as the load and rate predictions.

Low level optimizer 634 may control an inner (e.g., equipment level)loop of the cascaded optimization. Low level optimizer 634 may determinehow to best run each subplant at the load setpoint determined by highlevel optimizer 632. For example, low level optimizer 634 may determineon/off states and/or operating setpoints for various devices of thesubplant equipment in order to optimize (e.g., minimize) the energyconsumption of each subplant while meeting the resource allocationsetpoint for the subplant. In some embodiments, low level optimizer 634receives actual incentive events from incentive programs 602. Low leveloptimizer 634 may determine whether to participate in the incentiveevents based on the resource allocation set by high level optimizer 632.For example, if insufficient resources have been allocated to aparticular IBDR program by high level optimizer 632 or if the allocatedresources have already been used, low level optimizer 634 may determinethat energy storage system 500 will not participate in the IBDR programand may ignore the IBDR event. However, if the required resources havebeen allocated to the IBDR program and are available in storagesubplants 530, low level optimizer 634 may determine that system 500will participate in the IBDR program in response to the IBDR event. Thecascaded optimization process performed by demand response optimizer 630is described in greater detail in U.S. patent application Ser. No.15/247,885.

Still referring to FIG. 6A, memory 610 is shown to include a subplantcontrol module 628. Subplant control module 628 may store historicaldata regarding past operating statuses, past operating setpoints, andinstructions for calculating and/or implementing control parameters forsubplants 520-530. Subplant control module 628 may also receive, store,and/or transmit data regarding the conditions of individual devices ofthe subplant equipment, such as operating efficiency, equipmentdegradation, a date since last service, a lifespan parameter, acondition grade, or other device-specific data. Subplant control module628 may receive data from subplants 520-530 and/or BMS 606 viacommunications interface 636. Subplant control module 628 may alsoreceive and store on/off statuses and operating setpoints from low leveloptimizer 634.

Data and processing results from demand response optimizer 630, subplantcontrol module 628, or other modules of energy storage controller 506may be accessed by (or pushed to) monitoring and reporting applications626. Monitoring and reporting applications 626 may be configured togenerate real time “system health” dashboards that can be viewed andnavigated by a user (e.g., a system engineer). For example, monitoringand reporting applications 626 may include a web-based monitoringapplication with several graphical user interface (GUI) elements (e.g.,widgets, dashboard controls, windows, etc.) for displaying keyperformance indicators (KPI) or other information to users of a GUI. Inaddition, the GUI elements may summarize relative energy use andintensity across energy storage systems in different buildings (real ormodeled), different campuses, or the like. Other GUI elements or reportsmay be generated and shown based on available data that allow users toassess performance across one or more energy storage systems from onescreen. The user interface or report (or underlying data engine) may beconfigured to aggregate and categorize operating conditions by building,building type, equipment type, and the like. The GUI elements mayinclude charts or histograms that allow the user to visually analyze theoperating parameters and power consumption for the devices of the energystorage system.

Still referring to FIG. 6A, energy storage controller 506 may includeone or more GUI servers, web services 612, or GUI engines 614 to supportmonitoring and reporting applications 626. In various embodiments,applications 626, web services 612, and GUI engine 614 may be providedas separate components outside of energy storage controller 506 (e.g.,as part of a smart building manager). Energy storage controller 506 maybe configured to maintain detailed historical databases (e.g.,relational databases, XML databases, etc.) of relevant data and includescomputer code modules that continuously, frequently, or infrequentlyquery, aggregate, transform, search, or otherwise process the datamaintained in the detailed databases. Energy storage controller 506 maybe configured to provide the results of any such processing to otherdatabases, tables, XML files, or other data structures for furtherquerying, calculation, or access by, for example, external monitoringand reporting applications.

Energy storage controller 506 is shown to include configuration tools616. Configuration tools 616 can allow a user to define (e.g., viagraphical user interfaces, via prompt-driven “wizards,” etc.) how energystorage controller 506 should react to changing conditions in the energystorage subsystems. In an exemplary embodiment, configuration tools 616allow a user to build and store condition-response scenarios that cancross multiple energy storage system devices, multiple building systems,and multiple enterprise control applications (e.g., work ordermanagement system applications, entity resource planning applications,etc.). For example, configuration tools 616 can provide the user withthe ability to combine data (e.g., from subsystems, from eventhistories) using a variety of conditional logic. In varying exemplaryembodiments, the conditional logic can range from simple logicaloperators between conditions (e.g., AND, OR, XOR, etc.) to pseudo-codeconstructs or complex programming language functions (allowing for morecomplex interactions, conditional statements, loops, etc.).Configuration tools 616 can present user interfaces for building suchconditional logic. The user interfaces may allow users to definepolicies and responses graphically. In some embodiments, the userinterfaces may allow a user to select a pre-stored or pre-constructedpolicy and adapt it or enable it for use with their system.

Energy Cost Optimization Controller

Referring now to FIG. 6B, a block diagram illustrating controller 552 ingreater detail is shown, according to an exemplary embodiment.Controller 552 is shown providing control decisions to a buildingmanagement system (BMS) 606. In some embodiments, BMS 606 is the same orsimilar the BMS described with reference to FIG. 1. The controldecisions provided to BMS 606 may include resource purchase amounts forutilities 510 and/or setpoints for generator subplants 520.

BMS 606 may be configured to monitor conditions within a controlledbuilding or building zone. For example, BMS 606 may receive input fromvarious sensors (e.g., temperature sensors, humidity sensors, airflowsensors, voltage sensors, etc.) distributed throughout the building andmay report building conditions to controller 552. Building conditionsmay include, for example, a temperature of the building or a zone of thebuilding, a power consumption (e.g., electric load) of the building, astate of one or more actuators configured to affect a controlled statewithin the building, or other types of information relating to thecontrolled building. BMS 606 may operate subplants 520 to affect themonitored conditions within the building and to serve the thermal energyloads of the building.

BMS 606 may receive control signals from controller 552 specifyingon/off states and/or setpoints for the subplant equipment. BMS 606 maycontrol the equipment (e.g., via actuators, power relays, etc.) inaccordance with the control signals provided by controller 552. Forexample, BMS 606 may operate the equipment using closed loop control toachieve the setpoints specified by energy storage controller 552. Invarious embodiments, BMS 606 may be combined with controller 552 or maybe part of a separate building management system. According to anexemplary embodiment, BMS 606 is a METASYS® brand building managementsystem, as sold by Johnson Controls, Inc.

Controller 552 may monitor the status of the controlled building usinginformation received from BMS 606. Controller 552 may be configured topredict the thermal energy loads (e.g., heating loads, cooling loads,etc.) of the building for plurality of time steps in an optimizationperiod (e.g., using weather forecasts from a weather service 604).Controller 552 may generate control decisions that optimize the economicvalue of operating system 550 over the duration of the optimizationperiod subject to constraints on the optimization process (e.g., energybalance constraints, load satisfaction constraints, etc.). Theoptimization process performed by controller 552 is described in greaterdetail below.

Controller 552 is shown to include a communications interface 636 and aprocessing circuit 607 having a processor 608 and memory 610. Thesecomponents may be the same as described with reference to FIG. 6A. Forexample, controller 552 is shown to include demand response optimizer630. Demand response optimizer 630 may perform a cascaded optimizationprocess to optimize the performance of system 550. For example, demandresponse optimizer 630 is shown to include a high level optimizer 632and a low level optimizer 634. High level optimizer 632 may control anouter (e.g., subplant level) loop of the cascaded optimization. Highlevel optimizer 632 may determine an optimal set of control decisionsfor each time step in the prediction window in order to optimize (e.g.,maximize) the value of operating energy storage system 500. Controldecisions made by high level optimizer 632 may include, for example,load setpoints for each of generator subplants 520, resource purchaseamounts for each type of resource purchased from utilities 510, and/oran amount of each resource sold to energy purchasers 504. In otherwords, the control decisions may define resource allocation at each timestep.

Low level optimizer 634 may control an inner (e.g., equipment level)loop of the cascaded optimization. Low level optimizer 634 may determinehow to best run each subplant at the load setpoint determined by highlevel optimizer 632. For example, low level optimizer 634 may determineon/off states and/or operating setpoints for various devices of thesubplant equipment in order to optimize (e.g., minimize) the energyconsumption of each subplant while meeting the resource allocationsetpoint for the subplant. The cascaded optimization process performedby demand response optimizer 630 is described in greater detail in U.S.patent application Ser. No. 15/247,885. These and other components ofcontroller 552 may be the same as previously described with reference toFIG. 6A.

Planning Tool

Referring now to FIG. 7, a block diagram of a planning system 700 isshown, according to an exemplary embodiment. Planning system 700 may beconfigured to use demand response optimizer 630 as part of a planningtool 702 to simulate the operation of a central plant over apredetermined time period (e.g., a day, a month, a week, a year, etc.)for planning, budgeting, and/or design considerations. When implementedin planning tool 702, demand response optimizer 630 may operate in asimilar manner as described with reference to FIGS. 6A-6B. For example,demand response optimizer 630 may use building loads and utility ratesto determine an optimal resource allocation to minimize cost over asimulation period. However, planning tool 702 may not be responsible forreal-time control of a building management system or central plant.

Planning tool 702 can be configured to determine the benefits ofinvesting in a battery asset and the financial metrics associated withthe investment. Such financial metrics can include, for example, theinternal rate of return (IRR), net present value (NPV), and/or simplepayback period (SPP). Planning tool 702 can also assist a user indetermining the size of the battery which yields optimal financialmetrics such as maximum NPV or a minimum SPP. In some embodiments,planning tool 702 allows a user to specify a battery size andautomatically determines the benefits of the battery asset fromparticipating in selected IBDR programs while performing PBDR, asdescribed with reference to FIG. 5A. In some embodiments, planning tool702 is configured to determine the battery size that minimizes SPP giventhe IBDR programs selected and the requirement of performing PBDR. Insome embodiments, planning tool 702 is configured to determine thebattery size that maximizes NPV given the IBDR programs selected and therequirement of performing PBDR.

In planning tool 702, high level optimizer 632 may receive planned loadsand utility rates for the entire simulation period. The planned loadsand utility rates may be defined by input received from a user via aclient device 722 (e.g., user-defined, user selected, etc.) and/orretrieved from a plan information database 726. High level optimizer 632uses the planned loads and utility rates in conjunction with subplantcurves from low level optimizer 634 to determine an optimal resourceallocation (i.e., an optimal dispatch schedule) for a portion of thesimulation period.

The portion of the simulation period over which high level optimizer 632optimizes the resource allocation may be defined by a prediction windowending at a time horizon. With each iteration of the optimization, theprediction window is shifted forward and the portion of the dispatchschedule no longer in the prediction window is accepted (e.g., stored oroutput as results of the simulation). Load and rate predictions may bepredefined for the entire simulation and may not be subject toadjustments in each iteration. However, shifting the prediction windowforward in time may introduce additional plan information (e.g., plannedloads and/or utility rates) for the newly-added time slice at the end ofthe prediction window. The new plan information may not have asignificant effect on the optimal dispatch schedule since only a smallportion of the prediction window changes with each iteration.

In some embodiments, high level optimizer 632 requests all of thesubplant curves used in the simulation from low level optimizer 634 atthe beginning of the simulation. Since the planned loads andenvironmental conditions are known for the entire simulation period,high level optimizer 632 may retrieve all of the relevant subplantcurves at the beginning of the simulation. In some embodiments, lowlevel optimizer 634 generates functions that map subplant production toequipment level production and resource use when the subplant curves areprovided to high level optimizer 632. These subplant to equipmentfunctions may be used to calculate the individual equipment productionand resource use (e.g., in a post-processing module) based on theresults of the simulation.

Still referring to FIG. 7, planning tool 702 is shown to include acommunications interface 704 and a processing circuit 706.Communications interface 704 may include wired or wireless interfaces(e.g., jacks, antennas, transmitters, receivers, transceivers, wireterminals, etc.) for conducting data communications with varioussystems, devices, or networks. For example, communications interface 704may include an Ethernet card and port for sending and receiving data viaan Ethernet-based communications network and/or a WiFi transceiver forcommunicating via a wireless communications network. Communicationsinterface 704 may be configured to communicate via local area networksor wide area networks (e.g., the Internet, a building WAN, etc.) and mayuse a variety of communications protocols (e.g., BACnet, IP, LON, etc.).

Communications interface 704 may be a network interface configured tofacilitate electronic data communications between planning tool 702 andvarious external systems or devices (e.g., client device 722, resultsdatabase 728, plan information database 726, etc.). For example,planning tool 702 may receive planned loads and utility rates fromclient device 722 and/or plan information database 726 viacommunications interface 704. Planning tool 702 may use communicationsinterface 704 to output results of the simulation to client device 722and/or to store the results in results database 728.

Still referring to FIG. 7, processing circuit 706 is shown to include aprocessor 710 and memory 712. Processor 710 may be a general purpose orspecific purpose processor, an application specific integrated circuit(ASIC), one or more field programmable gate arrays (FPGAs), a group ofprocessing components, or other suitable processing components.Processor 710 may be configured to execute computer code or instructionsstored in memory 712 or received from other computer readable media(e.g., CDROM, network storage, a remote server, etc.).

Memory 712 may include one or more devices (e.g., memory units, memorydevices, storage devices, etc.) for storing data and/or computer codefor completing and/or facilitating the various processes described inthe present disclosure. Memory 712 may include random access memory(RAM), read-only memory (ROM), hard drive storage, temporary storage,non-volatile memory, flash memory, optical memory, or any other suitablememory for storing software objects and/or computer instructions. Memory712 may include database components, object code components, scriptcomponents, or any other type of information structure for supportingthe various activities and information structures described in thepresent disclosure. Memory 712 may be communicably connected toprocessor 710 via processing circuit 706 and may include computer codefor executing (e.g., by processor 710) one or more processes describedherein.

Still referring to FIG. 7, memory 712 is shown to include a GUI engine716, web services 714, and configuration tools 718. In an exemplaryembodiment, GUI engine 716 includes a graphical user interface componentconfigured to provide graphical user interfaces to a user for selectingor defining plan information for the simulation (e.g., planned loads,utility rates, environmental conditions, etc.). Web services 714 mayallow a user to interact with planning tool 702 via a web portal and/orfrom a remote system or device (e.g., an enterprise controlapplication).

Configuration tools 718 can allow a user to define (e.g., via graphicaluser interfaces, via prompt-driven “wizards,” etc.) various parametersof the simulation such as the number and type of subplants, the deviceswithin each subplant, the subplant curves, device-specific efficiencycurves, the duration of the simulation, the duration of the predictionwindow, the duration of each time step, and/or various other types ofplan information related to the simulation. Configuration tools 718 canpresent user interfaces for building the simulation. The user interfacesmay allow users to define simulation parameters graphically. In someembodiments, the user interfaces allow a user to select a pre-stored orpre-constructed simulated plant and/or plan information (e.g., from planinformation database 726) and adapt it or enable it for use in thesimulation.

Still referring to FIG. 7, memory 712 is shown to include demandresponse optimizer 630. Demand response optimizer 630 may use theplanned loads and utility rates to determine an optimal resourceallocation over a prediction window. The operation of demand responseoptimizer 630 may be the same or similar as previously described withreference to FIGS. 6-8. With each iteration of the optimization process,demand response optimizer 630 may shift the prediction window forwardand apply the optimal resource allocation for the portion of thesimulation period no longer in the prediction window. Demand responseoptimizer 630 may use the new plan information at the end of theprediction window to perform the next iteration of the optimizationprocess. Demand response optimizer 630 may output the applied resourceallocation to reporting applications 730 for presentation to a clientdevice 722 (e.g., via user interface 724) or storage in results database728.

Still referring to FIG. 7, memory 712 is shown to include reportingapplications 730. Reporting applications 730 may receive the optimizedresource allocations from demand response optimizer 630 and, in someembodiments, costs associated with the optimized resource allocations.Reporting applications 730 may include a web-based reporting applicationwith several graphical user interface (GUI) elements (e.g., widgets,dashboard controls, windows, etc.) for displaying key performanceindicators (KPI) or other information to users of a GUI. In addition,the GUI elements may summarize relative energy use and intensity acrossvarious plants, subplants, or the like. Other GUI elements or reportsmay be generated and shown based on available data that allow users toassess the results of the simulation. The user interface or report (orunderlying data engine) may be configured to aggregate and categorizeresource allocation and the costs associated therewith and provide theresults to a user via a GUI. The GUI elements may include charts orhistograms that allow the user to visually analyze the results of thesimulation. An exemplary output that may be generated by reportingapplications 730 is shown in FIG. 8.

Referring now to FIG. 8, several graphs 800 illustrating the operationof planning tool 702 are shown, according to an exemplary embodiment.With each iteration of the optimization process, planning tool 702selects an optimization period (i.e., a portion of the simulationperiod) over which the optimization is performed. For example, planningtool 702 may select optimization period 802 for use in the firstiteration. Once the optimal resource allocation 810 has been determined,planning tool 702 may select a portion 818 of resource allocation 810 tosend to plant dispatch 830. Portion 818 may be the first b time steps ofresource allocation 810. Planning tool 702 may shift the optimizationperiod 802 forward in time, resulting in optimization period 804. Theamount by which the prediction window is shifted may correspond to theduration of time steps b.

Planning tool 702 may repeat the optimization process for optimizationperiod 804 to determine the optimal resource allocation 812. Planningtool 702 may select a portion 820 of resource allocation 812 to send toplant dispatch 830. Portion 820 may be the first b time steps ofresource allocation 812. Planning tool 702 may then shift the predictionwindow forward in time, resulting in optimization period 806. Thisprocess may be repeated for each subsequent optimization period (e.g.,optimization periods 806, 808, etc.) to generate updated resourceallocations (e.g., resource allocations 814, 816, etc.) and to selectportions of each resource allocation (e.g., portions 822, 824) to sendto plant dispatch 830. Plant dispatch 830 includes the first b timesteps 818-824 from each of optimization periods 802-808. Once theoptimal resource allocation is compiled for the entire simulationperiod, the results may be sent to reporting applications 730, resultsdatabase 728, and/or client device 722, as described with reference toFIG. 7.

Resource Allocation Optimization

Referring now to FIG. 9, a block diagram illustrating high leveloptimizer 632 in greater detail is shown, according to an exemplaryembodiment. In some embodiments, high level optimizer 632 may beimplemented as a component of energy storage controller 506, asdescribed with reference to FIGS. 5A and 6A. In other embodiments, highlevel optimizer 632 may be implemented as a component of controller 552,as described with reference to FIGS. 5B and 6B. In other embodiments,high level optimizer 632 may be implemented as a component of planningtool 702, as described with reference to FIGS. 7-8.

High level optimizer 632 may receive load and rate predictions fromload/rate predictor 622, incentive predictions from incentive estimator620, and subplant curves from low level optimizer 634. High leveloptimizer 632 may determine an optimal resource allocation across energystorage system 500 as a function of the load and rate predictions, theincentive predictions, and the subplant curves. The optimal resourceallocation may include an amount of each resource purchased fromutilities 510, an amount of each input and output resource of generatorsubplants 520, an amount of each resource stored or withdrawn fromstorage subplants 530, and/or an amount of each resource sold to energypurchasers 504. In some embodiments, the optimal resource allocationmaximizes the economic value of operating energy storage system 500while satisfying the predicted loads for the building or campus.

High level optimizer 632 can be configured to optimize the utilizationof a battery asset, such as battery 108, battery 306, and/or electricalenergy storage subplant 533. A battery asset can be used to participatein IBDR programs which yield revenue and to reduce the cost of energyand the cost incurred from peak load contribution charges. High leveloptimizer 632 can use an optimization algorithm to optimally allocate abattery asset (e.g., by optimally charging and discharging the battery)to maximize its total value. In a planning tool framework, high leveloptimizer 632 can perform the optimization iteratively to determineoptimal battery asset allocation for an entire simulation period (e.g.,an entire year), as described with reference to FIG. 8. The optimizationprocess can be expanded to include economic load demand response (ELDR)and can account for peak load contribution charges. High level optimizer632 can allocate the battery asset at each time step (e.g., each hour)over a given horizon such that energy and demand costs are minimized andfrequency regulation (FR) revenue maximized. These and other features ofhigh level optimizer 632 are described in detail below.

Cost Function

Still referring to FIG. 9, high level optimizer 632 is shown to includea cost function module 902. Cost function module 902 can generate a costfunction or objective function which represents the total operating costof a system over a time horizon (e.g., one month, one year, one day,etc.). The system can include any of the systems previously described(e.g., frequency response optimization system 100, photovoltaic energysystem 300, energy storage system 500, planning system 700, etc.) or anyother system in which high level optimizer 632 is implemented. In someembodiments, the cost function can be expressed generically using thefollowing equation:

$\underset{x}{\arg\min}{J(x)}$

where J(x) is defined as follows:

${J(x)} = {\quad{\sum\limits_{sources}{\sum\limits_{horizon}{\quad{{cost}( {{purchase}_{{resource},{time}},{{time} - {\quad{\sum\limits_{incentives}{\sum\limits_{horizon}{{revenue}({ReservationAmount})}}}}}} }}}}}$

The first term in the previous equation represents the total cost of allresources purchased over the optimization horizon. Resources caninclude, for example, water, electricity, natural gas, or other types ofresources purchased from a utility or other outside entity. The secondterm in the equation represents the total revenue generated byparticipating in incentive programs (e.g., IBDR programs) over theoptimization horizon. The revenue may be based on the amount of powerreserved for participating in the incentive programs. Accordingly, thetotal cost function represents the total cost of resources purchasedminus any revenue generated from participating in incentive programs.

High level optimizer 632 can optimize the cost function J(x) subject tothe following constraint, which guarantees the balance between resourcespurchased, produced, discharged, consumed, and requested over theoptimization horizon:

${{\sum\limits_{sources}{purchase_{{resource},{time}}}} + {\sum\limits_{subplants}{{produces}\;( {x_{{internal},{time}},x_{{external},{time}},v_{{u{ncontrolled}},{time}}} )}} - {\sum\limits_{subplants}{{consumes}( {x_{{internal},{time}},x_{{external},{time}},v_{{u{ncontrolled}},{time}}} )}} + {\sum\limits_{{storage}s}{{discharges}_{resource}( {x_{{internal},{t{ime}}},x_{{external},{time}}} )}} - {\sum\limits_{si{nks}}{requests_{resource}}}} = 0$     ∀resources, ∀time ∈ horizon

where x_(internal,time) and x_(external,time) are internal and externaldecision variables and v_(uncontrolled,time) includes uncontrolledvariables.

The first term in the previous equation represents the total amount ofeach resource (e.g., electricity, water, natural gas, etc.) purchasedfrom each source (e.g., utilities 510) over the optimization horizon.The second term represents the total consumption of each resource withinthe system (e.g., by generator subplants 520) over the optimizationhorizon. The third term represents the total amount of each resourcedischarged from storage (e.g., storage subplants 530) over theoptimization horizon. Positive values indicate that the resource isdischarged from storage, whereas negative values indicate that theresource is charged or stored. The fourth term represents the totalamount of each resource requested by various resource sinks (e.g.,building 502, energy purchasers 504, or other resource consumers) overthe optimization horizon. Accordingly, this constraint ensures that thetotal amount of each resource purchased, produced, or discharged fromstorage is equal to the amount of each resource consumed, stored, orprovided to the resource sinks.

In some embodiments, cost function module 902 separates the purchasecost of one or more resources into multiple terms. For example, costfunction module 902 can separate the purchase cost of a resource into afirst term corresponding to the cost per unit of the resource purchased(e.g., $/kWh of electricity, $/liter of water, etc.) and a second termcorresponding to one or more demand charges. A demand charge is aseparate charge on the consumption of a resource which depends on themaximum or peak resource consumption over a given period (i.e., a demandcharge period). Cost function module 902 can express the cost functionusing the following equation:

${J(x)} = {{\sum\limits_{s \in {sources}}\lbrack {{\sum\limits_{q \in {demands}_{s}}{w_{{demand},s,q}r_{{demand},s,q}{\max\limits_{i \in {demand}_{s,q}}( {purchase}_{s,i} )}}} + {\sum\limits_{horizon}{r_{s,i}{purchase}_{s,i}}}} \rbrack} - {\sum\limits_{incentives}{\sum\limits_{{horizo}n}{{revenue}({ReservationAmount})}}}}$

where r_(demand,s,q) is the qth demand charge associated with the peakdemand of the resource provided by source s over the demand chargeperiod, w_(demand,s,q) is the weight adjustment of the qth demand chargeassociated with source s, and the max( ) term indicates the maximumamount of the resource purchased from source s at any time step i duringthe demand charge period. The variable r_(s,i) indicates the cost perunit of the resource purchased from source s and the variablepurchase_(s,i) indicates the amount of the resource purchased fromsource s during the ith time step of the optimization period.

In some embodiments, the energy system in which high level optimizer 632is implemented includes a battery asset (e.g., one or more batteries)configured to store and discharge electricity. If the battery asset isthe only type of energy storage, cost function module 902 can simplifythe cost function J(x) to the following equation:

${J(x)} = {{- {\overset{k + h - 1}{\sum\limits_{i = k}}{r_{e_{i}}P_{bat_{i}}}}} - {\overset{k + h - 1}{\sum\limits_{i = k}}{r_{FR_{i}}P_{FR_{i}}}} + {\overset{k + h - 1}{\sum\limits_{i = k}}{r_{s_{i}}{{P_{bat_{i}} - P_{bat_{i - 1}}}}}} + {w_{d}r_{d}{\max\limits_{i}( {{- P_{bat_{i}}} + {eLoad_{i}}} )}}}$

where h is the duration of the optimization horizon, P_(bat) _(i) is theamount of power (e.g., kW) discharged from the battery asset during theith time step of the optimization horizon for use in reducing the amountof power purchased from an electric utility, r_(e) _(i) is the price ofelectricity (e.g., $/kWh) at time step i, P_(FR,i) is the battery power(e.g., kW) committed to frequency regulation participation during timestep i, r_(FR) _(i) is the incentive rate (e.g., $/kWh) forparticipating in frequency regulation during time step i, r_(d) is theapplicable demand charge (e.g., $/kWh) associated with the maximumelectricity consumption during the corresponding demand charge period,w_(d) is a weight adjustment of the demand charge over the horizon, andthe max( ) term selects the maximum amount electricity purchased fromthe electric utility (e.g., kW) during any time step i of the applicabledemand charge period.

In the previous expression of the cost function J(x), the first termrepresents the cost savings resulting from the use of battery power tosatisfy the electric demand of the facility relative to the cost whichwould have been incurred if the electricity were purchased from theelectric utility. The second term represents the amount of revenuederived from participating in the frequency regulation program. Thethird term represents a switching penalty imposed for switching thebattery power P_(bat) between consecutive time steps. The fourth termrepresents the demand charge associated with the maximum amount ofelectricity purchased from the electric utility. The amount ofelectricity purchased may be equal to the difference between theelectric load of the facility eLoad_(i) (i.e., the total amount ofelectricity required) at time step i and the amount of power dischargedfrom the battery asset P_(bat) _(i) at time step i. In a planning toolframework, historical data of the electric load eLoad over the horizoncan be provided as a known input. In an operational mode, the electricload eLoad can be predicted for each time step of the optimizationperiod.

Optimization Constraints

Still referring to FIG. 9, high level optimizer 632 is shown to includea power constraints module 904. Power constraints module 904 may beconfigured to impose one or more power constraints on the objectivefunction J(x). In some embodiments, power constraints module 904generates and imposes the following constraints:

P _(bat) _(i) +P _(FR) _(i) ≤P _(eff)

−P _(bat) _(i) +P _(FR) _(i) ≤P _(eff)

P _(bat) _(i) +P _(FR) _(i) ≤eLoad_(i)

where P_(bat) _(i) is the amount of power discharged from the battery attime step i for use in satisfying electric demand and reducing thedemand charge, P_(FR) _(i) is the amount of battery power committed tofrequency regulation at time step i, P_(eff) is the effective poweravailable (e.g., the maximum rate at which the battery can be charged ordischarged), and eLoad_(i) is the total electric demand at time step i.

The first two power constraints ensure that the battery is not chargedor discharged at a rate that exceeds the maximum batterycharge/discharge rate P_(eff). If the system includes photovoltaic (PV)power generation, the effective power available P_(eff) can becalculated as follows:

P _(eff) =P _(rated) −P _(PV FirmingReserve)

where P_(rated) is the rated capacity of the battery andP_(PV FirmingReserve) is the PV firming reserve power. The third powerconstraint ensures that energy stored in the battery is not sold orexported to the energy grid. In some embodiments, power constraintsmodule 904 can remove the third power constraint if selling energy backto the energy grid is a desired feature or behavior of the system.

Still referring to FIG. 9, high level optimizer 632 is shown to includea capacity constraints module 906. Capacity constraints module 906 maybe configured to impose one or more capacity constraints on theobjective function J(x). The capacity constraints may be used to relatethe battery power P_(bat) charged or discharged during each time step tothe capacity and state-of-charge (SOC) of the battery. The capacityconstraints may ensure that the SOC of the battery is maintained withinacceptable lower and upper bounds and that sufficient battery capacityis available for frequency regulation. In some embodiments, the lowerand upper bounds are based on the battery capacity needed to reserve theamount of power committed to frequency regulation P_(FR) _(i) duringeach time step i.

In some embodiments, capacity constraints module 906 generates two setsof capacity constraints. One set of capacity constraints may apply tothe boundary condition at the end of each time step i, whereas the otherset of capacity constraints may apply to the boundary condition at thebeginning of the next time step i+1. For example, if a first amount ofbattery capacity is reserved for frequency regulation during time step iand a second amount of battery capacity is reserved for frequencyregulation during time step i+1, the boundary point between time step iand i+1 may be required to satisfy the capacity constraints for bothtime step i and time step i+1. This ensures that the decisions made forthe power committed to frequency regulation during the current time stepi and the next time step i+1 represent a continuous change in the SOC ofthe battery.

In some embodiments, capacity constraints module 906 generates thefollowing capacity constraints:

$\{ {{\begin{matrix}{{C_{a} - {\sum\limits_{n = k}^{i}P_{bat_{n}}}} \leq {C_{eff} - {C_{FR}P_{FR_{i}}}}} \\{{C_{a} - {\sum\limits_{n = k}^{i}P_{bat_{n}}}} \geq {C_{FR}P_{FR_{i}}}}\end{matrix}\mspace{14mu}{\forall i}} = {{k\mspace{14mu}\ldots\mspace{14mu} k} + h - {1\{ {{\begin{matrix}{{C_{a} - {\sum\limits_{n = k}^{i}P_{bat_{n}}}} \leq {C_{eff} - {C_{FR}P_{FR_{i + 1}}}}} \\{{C_{a} - {\sum\limits_{n = k}^{i}P_{bat_{n}}}} \geq {C_{FR}P_{FR_{i + 1}}}}\end{matrix}\mspace{14mu}{\forall i}} = {{k\mspace{14mu}\ldots\mspace{14mu} k} + h - 2}} }}} $

where C_(a) is the available battery capacity (e.g., kWh), C_(FR) is thefrequency regulation reserve capacity (e.g., kWh/kW) which translatesthe amount of battery power committed to frequency regulation P_(FR)into an amount of energy needed to be reserved, and C_(eff) is theeffective capacity of the battery.

The first set of constraints ensures that the battery capacity at theend of each time step i (i.e., available capacity C_(a) minus thebattery power discharged through time step i) is maintained between thelower capacity bound C_(FR)P_(FR) _(i) and the upper capacity boundC_(eff)−C_(FR)P_(FR) _(i) for time step i. The lower capacity boundC_(FR)P_(FR) _(i) represents the minimum capacity required to reserveP_(FR) _(i) for frequency regulation during time step i, whereas theupper capacity bound C_(eff)−C_(FR)P_(FR) _(i) represents maximumcapacity required to reserve P_(FR) _(i) for frequency regulation duringtime step i. Similarly, the second set of constraints ensures that thebattery capacity at the end of each time step i (i.e., availablecapacity C_(a) minus the battery power discharged through time step i)is maintained between the lower capacity bound C_(FR)P_(FR) _(i+1) andthe upper capacity bound C_(eff)−C_(FR)P_(FR) _(i+1) for time step i+1.The lower capacity bound C_(FR)P_(FR) _(i+1) represents the minimumcapacity required to reserve P_(FR) _(i+1) for frequency regulationduring time step i+1, whereas the upper capacity boundC_(eff)−C_(FR)P_(FR) _(i+1) represents maximum capacity required toreserve P_(FR) _(i+1) for frequency regulation during time step i+1.

In some embodiments, capacity constraints module 906 calculates theeffective capacity of the battery C_(eff) as a percentage of the ratedcapacity of the battery. For example, if frequency regulation andphotovoltaic power generation are both enabled and the SOC controlmargin is non-zero, capacity constraints module 906 can calculate theeffective capacity of the battery C_(eff) using the following equation:

C _(eff)=(1−C _(FR)−2C _(socCM))C _(rated) −C _(PV FirmingReserve)

where C_(socCM) is the control margin and C_(PV FirmingReserve) is thecapacity reserved for photovoltaic firming.

Still referring to FIG. 9, high level optimizer 632 is shown to includea switching constraints module 908. Switching constraints module 908 maybe configured to impose one or more switching constraints on the costfunction J(x). As previously described, the cost function J(x) mayinclude the following switching term:

$\sum\limits_{i = k}^{k + h - 1}{r_{s_{i}}{{P_{bat_{i}} - P_{bat_{i - 1}}}}}$

which functions as a penalty for switching the battery power P_(bat)between consecutive time steps i and i−1. Notably, the switching term isnonlinear as a result of the absolute value function.

Switching constraints module 908 can impose constraints which representthe nonlinear switching term in a linear format. For example, switchingconstraints module 908 can introduce an auxiliary switching variables_(i) and constrain the auxiliary switching variable to be greater thanthe difference between the battery power P_(bat) _(i) at time step i andthe battery power P_(bat) _(i−1) at time step i−1, as shown in thefollowing equations:

s _(i) >P _(bat) _(i) −P _(bat) _(i−1)

s _(i) >P _(bat) _(i−1) −P _(bat) _(i)

∀i=k . . . k+h−1

Switching constraints module 908 can replace the nonlinear switchingterm in the cost function J(x) with the following linearized term:

$\sum\limits_{i = k}^{k + h - 1}{r_{s_{i}}s_{i}}$

which can be optimized using any of a variety of linear optimizationtechniques (e.g., linear programming) subject to the constraints on theauxiliary switching variable s_(i).

Demand Charge Incorporation

Still referring to FIG. 9, high level optimizer 632 is shown to includea demand charge module 910. Demand charge module 910 can be configuredto modify the cost function J(x) and the optimization constraints toaccount for one or more demand charges. As previously described, demandcharges are costs imposed by utilities 510 based on the peak consumptionof a resource from utilities 510 during various demand charge periods(i.e., the peak amount of the resource purchased from the utility duringany time step of the applicable demand charge period). For example, anelectric utility may define one or more demand charge periods and mayimpose a separate demand charge based on the peak electric consumptionduring each demand charge period. Electric energy storage can helpreduce peak consumption by storing electricity in a battery when energyconsumption is low and discharging the stored electricity from thebattery when energy consumption is high, thereby reducing peakelectricity purchased from the utility during any time step of thedemand charge period.

In some instances, one or more of the resources purchased from utilities510 are subject to a demand charge or multiple demand charges. There aremany types of potential demand charges as there are different types ofenergy rate structures. The most common energy rate structures areconstant pricing, time of use (TOU), and real time pricing (RTP). Eachdemand charge may be associated with a demand charge period during whichthe demand charge is active. Demand charge periods can overlap partiallyor completely with each other and/or with the optimization period.Demand charge periods can include relatively long periods (e.g.,monthly, seasonal, annual, etc.) or relatively short periods (e.g.,days, hours, etc.). Each of these periods can be divided into severalsub-periods including off-peak, partial-peak, and/or on-peak. Somedemand charge periods are continuous (e.g., beginning 1/1/2017 andending 1/31/2017), whereas other demand charge periods arenon-continuous (e.g., from 11:00 AM-1:00 PM each day of the month).

Over a given optimization period, some demand charges may be activeduring some time steps that occur within the optimization period andinactive during other time steps that occur during the optimizationperiod. Some demand charges may be active over all the time steps thatoccur within the optimization period. Some demand charges may apply tosome time steps that occur during the optimization period and other timesteps that occur outside the optimization period (e.g., before or afterthe optimization period). In some embodiments, the durations of thedemand charge periods are significantly different from the duration ofthe optimization period.

Advantageously, demand charge module 910 may be configured to accountfor demand charges in the high level optimization process performed byhigh level optimizer 632. In some embodiments, demand charge module 910incorporates demand charges into the optimization problem and the costfunction J(x) using demand charge masks and demand charge rate weightingfactors. Each demand charge mask may correspond to a particular demandcharge and may indicate the time steps during which the correspondingdemand charge is active and/or the time steps during which the demandcharge is inactive. Each rate weighting factor may also correspond to aparticular demand charge and may scale the corresponding demand chargerate to the time scale of the optimization period.

As described above, the demand charge term of the cost function J(x) canbe expressed as:

${J(x)} = {\ldots{\sum\limits_{s \in {sources}}{\sum\limits_{q \in {demands_{s}}}{w_{{demand},s,q}r_{{demands},q}{\max\limits_{i \in {{de}mand_{s,q}}}{( {purchase}_{s,i} )\mspace{14mu}\ldots}}}}}}$

where the max( ) function selects the maximum amount of the resourcepurchased from source s during any time step i that occurs during theoptimization period. However, the demand charge period associated withdemand charge q may not cover all of the time steps that occur duringthe optimization period. In order to apply the demand charge q to onlythe time steps during which the demand charge q is active, demand chargemodule 910 can add a demand charge mask to the demand charge term asshown in the following equation:

${J(x)} = {\ldots\mspace{11mu}{\sum\limits_{s \in {sources}}{\sum\limits_{q \in {demands_{s}}}{w_{{demand},s,q}r_{{demand},s,q}{\max\limits_{i \in {{de}mand_{s,q}}}{( {g_{s,q,i}{purchase}_{s,i}} )\mspace{14mu}\ldots}}}}}}$

where g_(s,q,i) is an element of the demand charge mask.

The demand charge mask may be a logical vector including an elementg_(s,q,i) for each time step i that occurs during the optimizationperiod. Each element g_(s,q,i) of the demand charge mask may include abinary value (e.g., a one or zero) that indicates whether the demandcharge q for source s is active during the corresponding time step i ofthe optimization period. For example, the element g_(s,q,i) may have avalue of one (i.e., g_(s,q,i)=1) if demand charge q is active duringtime step i and a value of zero (i.e., g_(s,q,i)=0) if demand charge qis inactive during time step i. An example of a demand charge mask isshown in the following equation:

g _(s,q)=[0, 0, 0, 1, 1, 1, 1, 0, 0, 0, 1, 1]^(T)

where g_(s,q,1), g_(s,q,2), g_(s,q,3), g_(s,q,8), g_(s,q,9), andg_(s,q,10) have values of zero, whereas g_(s,q,4), g_(s,q,5), g_(s,q,6),g_(s,q,7), g_(s,q,11), and g_(s,q,12) have values of one. This indicatesthat the demand charge q is inactive during time steps i=1, 2, 3, 8, 9,10 (i.e., g_(s,q,i)=0 ∀i=1, 2, 3, 8, 9, 10) and active during time stepsi=4, 5, 6, 7, 11, 12 (i.e., g_(s,q,i)=1 ∀i=4, 5, 6, 7, 11, 12).Accordingly, the term g_(s,q,i) purchase_(s,i) within the max( )function may have a value of zero for all time steps during which thedemand charge q is inactive. This causes the max( ) function to selectthe maximum purchase from source s that occurs during only the timesteps for which the demand charge q is active.

In some embodiments, demand charge module 910 calculates the weightingfactor w_(demand,s,q) for each demand charge q in the cost functionJ(x). The weighting factor w_(demand,s,q) may be a ratio of the numberof time steps the corresponding demand charge q is active during theoptimization period to the number of time steps the corresponding demandcharge q is active in the remaining demand charge period (if any) afterthe end of the optimization period. For example, demand charge module910 can calculate the weighting factor w_(demand,s,q) using thefollowing equation:

$w_{{d{emand}},s,q} = \frac{\sum_{i = k}^{k + h - 1}g_{s,q,i}}{\sum_{i = {k + h}}^{period\_ end}g_{s,q,i}}$

where the numerator is the summation of the number of time steps thedemand charge q is active in the optimization period (i.e., from timestep k to time step k+h−1) and the denominator is the number of timesteps the demand charge q is active in the portion of the demand chargeperiod that occurs after the optimization period (i.e., from time stepk+h to the end of the demand charge period). The following exampleillustrates how demand charge module 910 can incorporate multiple demandcharges into the cost function J(x). In this example, a single source ofelectricity (e.g., an electric grid) is considered with multiple demandcharges applicable to the electricity source (i.e., q=1 . . . N, where Nis the total number of demand charges). The system includes a batteryasset which can be allocated over the optimization period by charging ordischarging the battery during various time steps. Charging the batteryincreases the amount of electricity purchased from the electric grid,whereas discharging the battery decreases the amount of electricitypurchased from the electric grid.

Demand charge module 910 can modify the cost function J(x) to accountfor the N demand charges as shown in the following equation:

${J(x)} = {\ldots + {w_{d_{1}}r_{d_{1}}{\max\limits_{i}( {g_{1_{i}}( {{- P_{{batt}_{i}}} + {eLoad}_{i}} )} )}} + \ldots + {w_{d_{q}}r_{d_{q}}{\max\limits_{i}( {g_{q_{i}}( {{- P_{{bat}_{i}}} + {eLoad}_{i}} )} )}} + \ldots + {w_{d_{N}}r_{d_{N}}{\max\limits_{i}( {g_{N_{i}}( {{- P_{{bat}_{i}}} + {eLoad}_{i}} )} )}}}$

where the term −P_(bat) _(i) +eLoad_(i) represents the total amount ofelectricity purchased from the electric grid during time step i (i.e.,the total electric load eLoad_(i) minus the power discharged from thebattery P_(bat) _(i) ) Each demand charge q=1 . . . N can be accountedfor separately in the cost function J(x) by including a separate max( )function for each of the N demand charges. The parameter r_(d) _(q)indicates the demand charge rate associated with the qth demand charge(e.g., $/kW) and the weighting factor w_(d) _(q) indicates the weightapplied to the qth demand charge.

Demand charge module 910 can augment each max( ) function with anelement g_(q) _(i) of the demand charge mask for the correspondingdemand charge. Each demand charge mask may be a logical vector of binaryvalues which indicates whether the corresponding demand charge is activeor inactive at each time step i of the optimization period. Accordingly,each max( ) function may select the maximum electricity purchase duringonly the time steps the corresponding demand charge is active. Each max() function can be multiplied by the corresponding demand charge rater_(d) _(q) and the corresponding demand charge weighting factor w_(d)_(q) to determine the total demand charge resulting from the batteryallocation P_(bat) over the duration of the optimization period.

In some embodiments, demand charge module 910 linearizes the demandcharge terms of the cost function J(x) by introducing an auxiliaryvariable d_(q) for each demand charge q. In the case of the previousexample, this will result in N auxiliary variables d₁ . . . d_(N) beingintroduced as decision variables in the cost function J(x). Demandcharge module 910 can modify the cost function J(x) to include thelinearized demand charge terms as shown in the following equation:

J(x)= . . . +w _(d) ₁ r _(d) ₁ d ₁ + . . . +w _(d) _(q) r _(d) _(q) d_(q) . . . +w _(d) _(N) r _(d) _(N) d _(N)

Demand charge module 910 can impose the following constraints on theauxiliary demand charge variables d₁ . . . d_(N) to ensure that eachauxiliary demand charge variable represents the maximum amount ofelectricity purchased from the electric utility during the applicabledemand charge period:

$d_{1} \geq {{g_{1_{i}}( {{- P_{bat_{i}}} + {eLoad_{i}}} )}\mspace{31mu}\begin{matrix}{{{\forall i} = {{k\mspace{14mu}\ldots\mspace{14mu} k} + h - 1}},{g_{1_{i}} \neq 0}} \\{d_{1} \geq {0\mspace{115mu}\vdots}}\end{matrix}}$$d_{q} \geq {{g_{q_{i}}( {{- P_{bat_{i}}} + {eLoad_{i}}} )}\mspace{31mu}\begin{matrix}{{{\forall i} = {{k\mspace{11mu}\ldots\mspace{14mu} k} + h - 1}},{g_{q_{i}} \neq 0}} \\{d_{q} \geq {0\mspace{121mu}\vdots}}\end{matrix}}$$d_{N} \geq {{g_{N_{i}}( {{- P_{bat_{i}}} + {eLoad_{i}}} )}\mspace{20mu}\begin{matrix}{{{\forall i} = {{k\mspace{14mu}\ldots\mspace{14mu} k} + h - 1}},{g_{N_{i}} \neq 0}} \\{d_{N} \geq {0\mspace{104mu}\vdots}}\end{matrix}}$

In some embodiments, the number of constraints corresponding to eachdemand charge q is dependent on how many time steps the demand charge qis active during the optimization period. For example, the number ofconstraints for the demand charge q may be equal to the number ofnon-zero elements of the demand charge mask g_(q). Furthermore, thevalue of the auxiliary demand charge variable d_(q) at each iteration ofthe optimization may act as the lower bound of the value of theauxiliary demand charge variable d_(q) at the following iteration.

Consider the following example of a multiple demand charge structure. Inthis example, an electric utility imposes three monthly demand charges.The first demand charge is an all-time monthly demand charge of 15.86$/kWh which applies to all hours within the entire month. The seconddemand charge is an on-peak monthly demand charge of 1.56 $/kWh whichapplies each day from 12:00-18:00. The third demand charge is apartial-peak monthly demand charge of 0.53 $/kWh which applies each dayfrom 9:00-12:00 and from 18:00-22:00.

For an optimization period of one day and a time step of one hour (i.e.,i=1 . . . 24), demand charge module 910 may introduce three auxiliarydemand charge variables. The first auxiliary demand charge variable d₁corresponds to the all-time monthly demand charge; the second auxiliarydemand charge variable d₂ corresponds to the on-peak monthly demandcharge; and the third auxiliary demand charge variable d₃ corresponds tothe partial-peak monthly demand charge. Demand charge module 910 canconstrain each auxiliary demand charge variable to be greater than orequal to the maximum electricity purchase during the hours thecorresponding demand charge is active, using the inequality constraintsdescribed above.

Demand charge module 910 can generate a demand charge mask g_(q) foreach of the three demand charges (i.e., q=1 . . . 3), where g_(q)includes an element for each time step of the optimization period (i.e.,g_(q)=[g_(q) ₁ . . . g_(q) ₂₄ ]). The three demand charge masks can bedefined as follows:

g ₁ _(i) =1 ∀i=1 . . . 24

g ₂ _(i) =1 ∀i=12 . . . 18

g ₃ _(i) =1 ∀i=9 . . . 12, 18 . . . 22

with all other elements of the demand charge masks equal to zero. Inthis example, it is evident that more than one demand charge constraintwill be active during the hours which overlap with multiple demandcharge periods. Also, the weight of each demand charge over theoptimization period can vary based on the number of hours the demandcharge is active, as previously described.

In some embodiments, demand charge module 910 considers severaldifferent demand charge structures when incorporating multiple demandcharges into the cost function J(x) and optimization constraints. Demandcharge structures can vary from one utility to another, or the utilitymay offer several demand charge options. In order to incorporate themultiple demand charges within the optimization framework, agenerally-applicable framework can be defined as previously described.Demand charge module 910 can translate any demand charge structure intothis framework. For example, demand charge module 910 can characterizeeach demand charge by rates, demand charge period start, demand chargeperiod end, and active hours. Advantageously, this allows demand chargemodule 910 to incorporate multiple demand charges in agenerally-applicable format.

The following is another example of how demand charge module 910 canincorporate multiple demand charges into the cost function J(x).Consider, for example, monthly demand charges with all-time, on-peak,partial-peak, and off-peak. In this case, there are four demand chargestructures, where each demand charge is characterized by twelve monthlyrates, twelve demand charge period start (e.g., beginning of eachmonth), twelve demand charge period end (e.g., end of each month), andhoursActive. The hoursActive is a logical vector where the hours over ayear where the demand charge is active are set to one. When running theoptimization over a given horizon, demand charge module 910 canimplement the applicable demand charges using the hoursActive mask, therelevant period, and the corresponding rate.

In the case of an annual demand charge, demand charge module 910 can setthe demand charge period start and period end to the beginning and endof a year. For the annual demand charge, demand charge module 910 canapply a single annual rate. The hoursActive demand charge mask canrepresent the hours during which the demand charge is active. For anannual demand charge, if there is an all-time, on-peak, partial-peak,and/or off-peak, this translates into at most four annual demand chargeswith the same period start and end, but different hoursActive anddifferent rates.

In the case of a seasonal demand charge (e.g., a demand charge for whichthe maximum peak is determined over the indicated season period), demandcharge module 910 can represent the demand charge as an annual demandcharge. Demand charge module 910 can set the demand charge period startand end to the beginning and end of a year. Demand charge module 910 canset the hoursActive to one during the hours which belong to the seasonand to zero otherwise. For a seasonal demand charge, if there is anAll-time, on-peak, partial, and/or off-peak, this translates into atmost four seasonal demand charges with the same period start and end,but different hoursActive and different rates.

In the case of the average of the maximum of current month and theaverage of the maxima of the eleven previous months, demand chargemodule 910 can translate the demand charge structure into a monthlydemand charge and an annual demand charge. The rate of the monthlydemand charge may be half of the given monthly rate and the annual ratemay be the sum of given monthly rates divided by two. These and otherfeatures of demand charge module 910 are described in greater detail inU.S. patent application Ser. No. 15/405,236 filed Jan. 12, 2017, theentire disclosure of which is incorporated by reference herein.

Incentive Program Incorporation

Referring again to FIG. 9, high level optimizer 632 is shown to includean incentive program module 912. Incentive program module 912 may modifythe optimization problem to account for revenue from participating in anincentive-based demand response (IBDR) program. IBDR programs mayinclude any type of incentive-based program that provides revenue inexchange for resources (e.g., electric power) or a reduction in a demandfor such resources. For example, energy storage system 500 may provideelectric power to an energy grid or an independent service operator aspart of a frequency response program (e.g., PJM frequency response) or asynchronized reserve market. In a frequency response program, aparticipant contracts with an electrical supplier to maintain reservepower capacity that can be supplied or removed from an energy grid bytracking a supplied signal. The participant is paid by the amount ofpower capacity required to maintain in reserve. In other types of IBDRprograms, energy storage system 500 may reduce its demand for resourcesfrom a utility as part of a load shedding program. It is contemplatedthat energy storage system 500 may participate in any number and/or typeof IBDR programs.

In some embodiments, incentive program module 912 modifies the costfunction J(x) to include revenue generated from participating in aneconomic load demand response (ELDR) program. ELDR is a type of IBDRprogram and similar to frequency regulation. In ELDR, the objective isto maximize the revenue generated by the program, while using thebattery to participate in other programs and to perform demandmanagement and energy cost reduction. To account for ELDR programparticipation, incentive program module 912 can modify the cost functionJ(x) to include the following term:

$\min\limits_{b_{i},P_{bat_{i}}}( {- {\sum\limits_{i = k}^{k + h - 1}{b_{i}{r_{ELDR_{i}}( {{adjCBL_{i}} - ( {{eLoad_{i}} - P_{bat_{i}}} )} )}}}} )$

where b_(i) is a binary decision variable indicating whether toparticipate in the ELDR program during time step i r_(ELDR) _(i) is theELDR incentive rate at which participation is compensated, andadjCBL_(i) is the symmetric additive adjustment (SAA) on the baselineload. The previous expression can be rewritten as:

$\min\limits_{b_{i},P_{bat_{i}}}( {- {\sum\limits_{i = k}^{k + h - 1}{b_{i}{r_{ELDR_{i}}( {{\sum\limits_{l = 1}^{4}\frac{e_{li}}{4}} + {\sum\limits_{p = {m - 4}}^{m - 2}{\frac{1}{3}( {{eLoad_{p}} - P_{bat_{p}} - {\sum\limits_{l = 1}^{4}\frac{e_{lp}}{4}}} )}} - ( {{eLoad_{i}} - P_{bat_{i}}} )} )}}}} )$

where e_(li) and e_(lp) are the electric loads at the lth hour of theoperating day.

In some embodiments, incentive program module 912 handles theintegration of ELDR into the optimization problem as a bilinear problemwith two multiplicative decision variables. In order to linearize thecost function J(x) and customize the ELDR problem to the optimizationframework, several assumptions may be made. For example, incentiveprogram module 912 can assume that ELDR participation is only in thereal-time market, balancing operating reserve charges and make wholepayments are ignored, day-ahead prices are used over the horizon,real-time prices are used in calculating the total revenue from ELDRafter the decisions are made by the optimization algorithm, and thedecision to participate in ELDR is made in advance and passed to theoptimization algorithm based on which the battery asset is allocated.

In some embodiments, incentive program module 912 calculates theparticipation vector b_(i) as follows:

$b_{i} = \{ \begin{matrix}1 & {\forall{{{i/r_{{DA}_{i}}} \geq {{NBT}_{i}\mspace{14mu}{and}\mspace{14mu} i}} \in S}} \\0 & {otherwise}\end{matrix} $

where r_(DA) _(i) is the hourly day-ahead price at the ith hour, NBT isthe net benefits test value corresponding to the month to which thecorresponding hour belongs, and S is the set of nonevent days. Noneventdays can be determined for the year by choosing to participate every xnumber of days with the highest day-ahead prices out of y number of daysfor a given day type. This approach may ensure that there are noneventdays in the 45 days prior to a given event day when calculating the CBLfor the event day.

Given these assumptions and the approach taken by incentive programmodule 912 to determine when to participate in ELDR, incentive programmodule 912 can adjust the cost function J(x) as follows:

${J(x)} = {{- {\overset{k + h - 1}{\sum\limits_{i = k}}{r_{e_{i}}P_{bat_{i}}}}} - {\overset{k + h - 1}{\sum\limits_{i = k}}{r_{FR_{i}}P_{FR_{i}}}} + {\overset{k + h - 1}{\sum\limits_{i = k}}{r_{s_{i}}s_{i}}} + {w_{d}r_{d}d} - {\underset{i = k}{\sum\limits^{k + h - 1}}{b_{i}{r_{DA_{i}}( {{\sum\limits_{p = {m - 4}}^{m - 2}{{- \frac{1}{3}}P_{bat_{p}}}} + P_{bat_{i}}} )}}}}$

where b_(i) and m are known over a given horizon. The resulting termcorresponding to ELDR shows that the rates at the ith participation hourare doubled and those corresponding to the SAA are lowered. This meansit is expected that high level optimizer 632 will tend to charge thebattery during the SAA hours and discharge the battery during theparticipation hours. Notably, even though a given hour is set to be anELDR participation hour, high level optimizer 632 may not decide toallocate any of the battery asset during that hour. This is due to thefact that it may be more beneficial at that instant to participate inanother incentive program or to perform demand management.

Peak Load Contribution Incorporation

Still referring to FIG. 9, high level optimizer 632 is shown to includea peak load contribution module 914. Peak load contribution (PLC) is acustomer's contribution to regional demand peaks that occur ingeographic area managed by a regional transmission organization (RTO) orindependent system operator (ISO) at certain hours within a base period.The regional demand at a given hour may be the summation of thecustomer's demand during (i.e., the rate at which the customer purchaseselectricity or another resource from a utility) as well as the demand ofother buildings in the geographic area during that hour. The customermay be billed based on its contribution to the peak regional demand(e.g., $/kW of the customer's PLC) in addition to the energy consumptioncharges and demand charges previously described.

PLC module 914 can be configured to modify the cost function J(x) toaccount for a cost associated with the customer's PLC. By incorporatingPLC costs into the cost function J(x), PLC module 914 enables high leveloptimizer 632 to allocate resource consumption and resource purchases toreduce the customer's PLC. High level optimizer 632 can reduce PLC costsby shifting the customer's load to non-peak times or shaving thecustomer's peak load. This can be done, for example, by precooling thebuilding during non-peak times, using thermal energy storage, and/orusing electrical energy storage such as a battery asset.

Accounting for the cost associated with the customer's PLC can be moredifficult than accounting for energy consumption costs and demandcharges. Unlike demand charge which is calculated based on thecustomer's maximum demand during predetermined demand charge periods,the hours over which PLC is calculated may not be known in advance. Thehours of peak regional demand (i.e., the coincidental peak (CP) hours)may not be known until the end of the base period over which PLC iscalculated. For example, the CP hours for a given base period (e.g., oneyear) may be determined by a RTO at the end of the base period based onthe demand of all the buildings within the geographic area managed bythe RTO during the base period (e.g., by selecting the hours with thehighest regional demand). The customer's PLC may then be determinedbased on the customer's demand during the designated CP hours and usedto calculate a cost of the customer's PLC. This cost may then be billedto the customer during the next time period (e.g., the next year),referred to as the billing period.

Another difficulty in accounting for PLC costs is that the base period,billing period, CP hours, and other factors used to calculate the PLCcost may differ from one RTO to another. For example, a RTO for thePennsylvania, Jersey, and Maryland (PJM) geographic area may define thebase period (i.e., the peak-setting period) as June 1^(st) of year Y toMay 31^(st) of year Y+1. The billing period (i.e., the delivery period)may be defined as June 1^(st) of year Y+1 to May 31^(st) of year Y+2.PJM may define the CP hours as the five hours with the highest loadsover the five highest peak load days across the PJM geographic region.

A customer's PLC in the PJM region may be calculated as the product ofthe customer's average electric load during the five CP hours and acapacity loss factor (CLF), as shown in the following equation:

${PLC_{cu{stomer}}} = {CLF \times {\sum\limits_{i = 1}^{5}\frac{eLoad_{cp_{i}}}{5}}}$

where PLC_(customer) is the customer's peak load contribution calculatedduring year Y, CLF is the capacity loss factor (e.g., CLF=1.05), andeLoad_(cp) _(i) is the customer's electric load (e.g., kW) during theith CP hour.

The customer's PLC cost in the PJM region can be calculated as theproduct of the customer's PLC during year Y and a PLC rate, as shown inthe following equation:

PLC_(cost) =r _(PLC)×PLC_(customer)

where PLC_(cost) is the customer's PLC charge billed over the deliveryyear Y+1 (e.g., $) and r_(PLC) is the rate at which the customer ischarged for its PLC (e.g., $/kW).

An additional complication in the PJM region relates to the interactionbetween PLC costs and economic load demand response (ELDR) revenue. Insome embodiments, a customer participating in ELDR in the PJM regionduring one of the CP hours may be prohibited from reducing its PLC whileearning ELDR revenue at the same time. Accordingly, a customer wishingto reduce its load during an assumed CP hour for the purpose of reducingits capacity, transmission, and/or demand charge costs may be restrictedfrom making a bid for the same assumed CP hour in the ELDR market.

Another example of an organization which imposes PLC costs is theindependent electricity system operator (IESO) in Ontario, Canada.Relative to PJM, IESO may use a different base period, billing period,CP hours, and other factors used to calculate the PLC cost. For example,IESO may define the base period or peak-setting period as May 1^(st) ofyear Y to April 30^(th) of year Y+1. The billing period or adjustmentperiod for IESO may be defined as July 1^(st) of year Y+1 to June30^(th) of year Y+2. IESO may define the CP hours as the five hours withthe highest regional demands across the IESO geographic region.

At the end of the base period, IESO may calculate the customer's peakdemand factor (θ_(PDF)). The peak demand factor may be defined as theratio of the sum of the customer's peak demand to the sum of theregion-wide demand peaks during the five CP hours, as shown in thefollowing equation:

$\theta_{PDF} = \frac{\sum_{i = 1}^{5}{eLoad_{cp_{i}}}}{\sum_{i = 1}^{5}{sysLoad_{cp_{i}}}}$

where sysLoad_(cp) _(i) is the region-wide peak load during the ith CPhour and eLoad_(cp) _(i) is the customer's peak load during the ith CPhour.

The customer's PLC cost in the IESO region is known as a globaladjustment (GA) charge. The GA charge may be imposed as a monthly chargeduring the billing period. In some embodiments, the GA charge iscalculated by multiplying the customer's peak demand factor by themonthly region-wide global adjustment costs, as shown in the followingequation:

GA _(cost,month)=θ_(PDF) ×GA _(total,month)

where GA_(cost,month) is the customer's monthly PLC cost (e.g., $) andGA_(total,month) is the region-wide global adjustment cost (e.g., $).The value of GA_(total,month) may be specified by IESO. In someembodiments, GA_(total,month) has a known value. In other embodiments,the value of GA_(total,month) may not be known until the end of the baseperiod.

In order to incorporate PLC costs into the cost function J(x) andallocate resource consumption/purchases in advance, PLC module 914 cangenerate or obtain a projection of the CP hours for an upcoming baseperiod. The projected CP hours can then be used by high level optimizer632 as an estimate of the actual CP hours. High level optimizer 632 canuse the projected CP hours to allocate one or more assets (e.g., abattery, thermal energy storage, HVAC equipment, etc.) to minimize thecustomer's demand during the projected CP hours. These and otherfeatures of PLC module 914 are described in greater detail in U.S.patent application Ser. No. 15/405,234 filed Jan. 12, 2017, the entiredisclosure of which is incorporated by reference herein.

Asset Sizing Incorporation

Still referring to FIG. 9, high level optimizer 632 is shown to includean asset sizing module 916. Asset sizing module 916 can be configured todetermine the optimal sizes of various assets in a building, group ofbuildings, or a central plant. Assets can include individual pieces ofequipment or groups of equipment. For example, assets can includeboilers, chillers, heat recovery chillers, steam generators, electricalgenerators, thermal energy storage tanks, batteries, air handling units,or other types of equipment in a building or a central plant (e.g., HVACequipment, BMS equipment, etc.). In some embodiments, assets includecollections of equipment which form a subplant of a central plant (e.g.,central plant 118). For example, assets can include heater subplant 521,chiller subplant 522, heat recovery chiller subplant 523, steam subplant524, electricity subplant 525, or any other type of generator subplant520. In some embodiments, assets include hot thermal energy storage 531(e.g., one or more hot water storage tanks), cold thermal energy storage532 (e.g., one or more cold thermal energy storage tanks), electricalenergy storage 533 (e.g., one or more batteries), or any other type ofstorage subplant 530.

Asset sizes can include a maximum loading of the asset and/or a maximumcapacity of the asset. Some assets such as storage subplants 530 mayhave both a maximum loading and a maximum capacity. For example, batteryassets may have a maximum battery power (e.g., a maximum rate at whichthe battery can be charged or discharged) and a maximum state-of-charge(e.g., a maximum energy storage of the battery). Similarly, thermalenergy storage assets may have a maximum charge/discharge rate and amaximum capacity (e.g., maximum fluid storage, etc.). Other assets suchas generator subplants 520 may have only a maximum loading. For example,a chiller may have a maximum rate at which the chiller can produce coldthermal energy. Similarly, an electric generator may have a maximum rateat which the generator can produce electricity. Asset sizing module 916can be configured to determine the maximum loading and/or the maximumcapacity of an asset when determining the optimal size of the asset.

In some embodiments, asset sizing module 916 is implemented a componentof planning tool 702. In the planning tool framework, asset sizingmodule 916 can determine the optimal size of an asset for a givenapplication. For example, consider the planning problem described withreference to FIGS. 7-8 in which the high level optimization is solved ata given time instant k over a given time horizon h. With each iterationof the high level optimization, the time horizon h can be shiftedforward by a block size equivalent to b time steps and the first b setsof decision variables may be retained. In such a planning problem, thesizes of the assets to be optimally allocated are typically given alongwith historical load data, utility pricing, and other relative data.However, there are many cases in which the sizes of the assets to beallocated are unknown. For example, when purchasing a new asset for agiven application (e.g., adding thermal energy storage or electricalenergy storage to a building or central plant), a user may wish todetermine the optimal size of the asset to purchase.

Asset sizing module 916 can be configured to determine the optimal sizeof an asset by considering the potential benefits and costs of theasset. Potential benefits can include, for example, reduced energycosts, reduced demand charges, reduced PLC charges, and/or increasedrevenue from participating in IBDR programs such as frequency regulation(FR) or economic load demand response (ELDR). Potential costs caninclude fixed costs (e.g., an initial purchase cost of the asset) aswell as marginal costs (e.g., ongoing costs of using the asset) over thetime horizon. The potential benefits and costs of an asset may varybased on the application of the asset and/or the system in which theasset will be used. For example, a system that participates in FRprograms may realize the benefit of increased IBDR revenue, whereas asystem that does not participate in any IBDR programs may not realizesuch a benefit.

Some of the benefits and costs of an asset may be captured by theoriginal cost function J(x). For example, the cost function J(x) mayinclude terms corresponding to energy cost, multiple demand charges, PLCcharges, and/or IBDR revenue, as previously described. Adding one ormore new assets may affect the values of some or all of these terms inthe original cost function J(x). For example, adding a battery asset mayincrease IBDR revenue and decrease energy cost, demand charges, and PLCcharges. However, the original cost function J(x) may not account forthe fixed and marginal costs resulting from new asset purchases. Inorder to account for these fixed and marginal costs, asset sizing module916 may add new terms to the original cost function J(x).

Asset sizing module 916 can be configured to augment the cost functionJ(x) with two new terms that correspond to the cost of purchasing thenew assets, resulting in an augmented cost function J_(a)(x). Theadditional terms are shown in the following equation:

J _(a)(x)=J(x)+c _(f) ^(T) v+c _(s) ^(T) s _(a)

where J(x) is the original cost function, x is the vector of decisionvariables of the optimization problem over the horizon, c_(f) is avector of fixed costs of buying any size of asset (e.g., one element foreach potential asset purchase), v is a vector of binary decisionvariables that indicate whether the corresponding assets are purchased,c_(s) is a vector of marginal costs per unit of asset size (e.g., costper unit loading, cost per unit capacity), and s_(a) is a vector ofcontinuous decision variables corresponding to the asset sizes.Advantageously, the binary purchase decisions and asset size decisionsare treated as decision variables which can be optimized along with thedecision variables in the vector x. This allows high level optimizer 632to perform a single optimization to determine optimal values for all ofthe decision variables in the augmented cost function J_(a)(x).

In some embodiments, asset sizing module 916 scales the asset purchasecosts c_(f) ^(T)v and c_(s) ^(T)s_(a) to the duration of theoptimization period h. The cost of purchasing an asset is typically paidover an entire payback period SPP, whereas the operational cost is onlyover the optimization period h. In order to scale the asset purchasecosts to the optimization period, asset sizing module 916 can multiplythe terms c_(f) ^(T)v and c_(s) ^(T)s_(a) by the ratio

$\frac{h}{SPP}$

as shown in the following equation:

${J_{a}(x)} = {{J(x)} + {\frac{h}{8760 \cdot {SPP}}( {{c_{f}^{T}v} + {c_{s}^{T}s_{a}}} )}}$

where h is the duration of the optimization period in hours, SPP is theduration of the payback period in years, and 8760 is the number of hoursin a year.

High level optimizer 632 can perform an optimization process todetermine the optimal values of each of the binary decision variables inthe vector v and each of the continuous decision variables in the vectors_(a). In some embodiments, high level optimizer 632 uses linearprogramming (LP) or mixed integer linear programming (MILP) to optimizea financial metric such as net present value (NPV), simple paybackperiod (SPP), or internal rate of return (IRR). Each element of thevectors c_(f), v, c_(s), and s_(a) may correspond to a particular assetand/or a particular asset size. Accordingly, high level optimizer 632can determine the optimal assets to purchase and the optimal sizes topurchase by identifying the optimal values of the binary decisionvariables in the vector v and the continuous decision variables in thevector s_(a).

Subplant Curve Incorporation

Still referring to FIG. 9, high level optimizer 632 is shown to includea subplant curves module 930. In the simplest case, it can be assumedthat the resource consumption of each subplant is a linear function ofthe thermal energy load produced by the subplant. However, thisassumption may not be true for some subplant equipment, much less for anentire subplant. Subplant curves module 930 may be configured to modifythe high level optimization problem to account for subplants that have anonlinear relationship between resource consumption and load production.

Subplant curves module 930 is shown to include a subplant curve updater932, a subplant curves database 934, a subplant curve linearizer 936,and a subplant curves incorporator 938. Subplant curve updater 932 maybe configured to request subplant curves for each of subplants 520-530from low level optimizer 634. Each subplant curve may indicate an amountof resource consumption by a particular subplant (e.g., electricity usemeasured in kW, water use measured in L/s, etc.) as a function of thesubplant load.

In some embodiments, low level optimizer 634 generates the subplantcurves by running the low level optimization process for variouscombinations of subplant loads and weather conditions to generatemultiple data points. Low level optimizer 634 may fit a curve to thedata points to generate the subplant curves and provide the subplantcurves to subplant curve updater 832. In other embodiments, low leveloptimizer 634 provides the data points to subplant curve updater 932 andsubplant curve updater 932 generates the subplant curves using the datapoints. Subplant curve updater 932 may store the subplant curves insubplant curves database 934 for use in the high level optimizationprocess.

In some embodiments, the subplant curves are generated by combiningefficiency curves for individual devices of a subplant. A deviceefficiency curve may indicate the amount of resource consumption by thedevice as a function of load. The device efficiency curves may beprovided by a device manufacturer or generated using experimental data.In some embodiments, the device efficiency curves are based on aninitial efficiency curve provided by a device manufacturer and updatedusing experimental data. The device efficiency curves may be stored inequipment models 618. For some devices, the device efficiency curves mayindicate that resource consumption is a U-shaped function of load.Accordingly, when multiple device efficiency curves are combined into asubplant curve for the entire subplant, the resultant subplant curve maybe a wavy curve. The waves are caused by a single device loading upbefore it is more efficient to turn on another device to satisfy thesubplant load.

Subplant curve linearizer 936 may be configured to convert the subplantcurves into convex curves. A convex curve is a curve for which a lineconnecting any two points on the curve is always above or along thecurve (i.e., not below the curve). Convex curves may be advantageous foruse in the high level optimization because they allow for anoptimization process that is less computationally expensive relative toan optimization process that uses non-convex functions. Subplant curvelinearizer 936 may be configured to break the subplant curves intopiecewise linear segments that combine to form a piecewise-definedconvex curve. Subplant curve linearizer 936 may store the linearizedsubplant curves in subplant curves database 934.

Subplant curve incorporator 938 may be configured to modify the highlevel optimization problem to incorporate the subplant curves into theoptimization. In some embodiments, subplant curve incorporator 938modifies the decision variables to include one or more decision vectorsrepresenting the resource consumption of each subplant. Subplant curveincorporator 938 may modify the inequality constraints to ensure thatthe proper amount of each resource is consumed to serve the predictedthermal energy loads. In some embodiments, subplant curve incorporator938 formulates inequality constraints that force the resource usage foreach resource in the epigraph of the corresponding linearized subplantcurve. For example, chiller subplant 522 may have a linearized subplantcurve that indicates the electricity use of chiller subplant 522 (i.e.,input resource in₁) as a function of the cold water production ofchiller subplant 522 (i.e., output resource out₁). The linearizedsubplant curve may include a first line segment connecting point [u₁,Q₁] to point [u₂, Q₂], a second line segment connecting point [u₂, Q₂]to point [u₃, Q₃], and a third line segment connecting point [u₃, Q₃] topoint [u₄, Q₄].

Subplant curve incorporator 938 may formulate an inequality constraintfor each piecewise segment of the subplant curve that constrains thevalue of the decision variable representing chiller electricity use tobe greater than or equal to the amount of electricity use defined by theline segment for the corresponding value of the cold water production.Similar inequality constraints can be formulated for other subplantcurves. For example, subplant curve incorporator 938 may generate a setof inequality constraints for the water consumption of chiller subplant522 using the points defining the linearized subplant curve for thewater consumption of chiller subplant 522 as a function of cold waterproduction. In some embodiments, the water consumption of chillersubplant 522 is equal to the cold water production and the linearizedsubplant curve for water consumption includes a single line segmentconnecting point [u₅, Q₅] to point [u₆, Q₆]. Subplant curve incorporator938 may repeat this process for each subplant curve for chiller subplant522 and for the other subplants of the central plant to define a set ofinequality constraints for each subplant curve.

The inequality constraints generated by subplant curve incorporator 938ensure that high level optimizer 632 keeps the resource consumptionabove all of the line segments of the corresponding subplant curve. Inmost situations, there is no reason for high level optimizer 632 tochoose a resource consumption value that lies above the correspondingsubplant curve due to the economic cost associated with resourceconsumption. High level optimizer 632 can therefore be expected toselect resource consumption values that lie on the correspondingsubplant curve rather than above it.

The exception to this general rule is heat recovery chiller subplant523. The equality constraints for heat recovery chiller subplant 523provide that heat recovery chiller subplant 523 produces hot water at arate equal to the subplant's cold water production plus the subplant'selectricity use. The inequality constraints generated by subplant curveincorporator 938 for heat recovery chiller subplant 523 allow high leveloptimizer 632 to overuse electricity to make more hot water withoutincreasing the amount of cold water production. This behavior isextremely inefficient and only becomes a realistic possibility when thedemand for hot water is high and cannot be met using more efficienttechniques. However, this is not how heat recovery chiller subplant 523actually operates.

To prevent high level optimizer 632 from overusing electricity, subplantcurve incorporator 938 may check whether the calculated amount ofelectricity use (determined by the optimization algorithm) for heatrecovery chiller subplant 523 is above the corresponding subplant curve.In some embodiments, the check is performed after each iteration of theoptimization algorithm. If the calculated amount of electricity use forheat recovery chiller subplant 523 is above the subplant curve, subplantcurve incorporator 938 may determine that high level optimizer 632 isoverusing electricity. In response to a determination that high leveloptimizer 632 is overusing electricity, subplant curve incorporator 938may constrain the production of heat recovery chiller subplant 523 atits current value and constrain the electricity use of subplant 523 tothe corresponding value on the subplant curve. High level optimizer 632may then rerun the optimization with the new equality constraints. Theseand other features of subplant curves module 930 are described ingreater detail in U.S. patent application Ser. No. 14/634,609 filed Feb.27, 2015, the entire disclosure of which is incorporated by referenceherein.

Economic Load Demand Response (ELDR)

An ELDR program is a type of IBDR program that allows a customer withina region managed by an RTO and/or ISO offering the ELDR program theability to generate revenue by reducing the electric consumption of abuilding, facility, or campus owned by the customer during certain hoursof a day. The customer can choose particular hours of a day during whichthe customer would like to participate in the ELDR program. These hoursmay be times that the electric load of a building owned by the customerwill be reduced below a baseline load. FIG. 12 provides an illustrationof an electric load over time for a building participating in an ELDRprogram.

In an ELDR program, a customer is compensated for a reduction inelectric load based on an electric load of a building during theparticipation of the ELDR program with respect to a customer baselineload (CBL). The CBL may be a load specific to a particular customer andthe typical electric loads of the customer. Further, there may bedifferent types of CBLs. In some cases, there are two types of CBLs, asame day CBL and a symmetric additive adjustment (SAA) CBL. A same dayCBL may be entirely dependent on the electric load on the day that thecustomer participates in the ELDR program, the participation day. TheSAA CBL may be dependent on electric loads of previous days in additionto the electric load of the participation day. The same day CBL isillustrated in FIG. 13 while the SAA CBL is illustrated FIG. 14.

An ELDR program, such as the ELDR program discussed herein, may includemultiple markets in which a customer can participate. In some cases, themarkets are a day-ahead market and a real-time market.

Day-Ahead Market

In the day-ahead market, a customer may submit a bid to the RTO and/orISO by a predefined time (e.g., 10:30 A.M.) for the following day, theparticipation day. The bid may be submitted via a curtailment serviceprovider (CSP). The CSP may act as a medium between a customer and theRTO and/or ISO. The bid may include the hours that the customer wouldlike to participate in the ELDR program, an amount that the customerwill curtail their electric load by, a minimum number of hours that thecustomer wants to participate, and/or an amount or rate at which thecustomer would like to be compensated. In various cases, a customer isallowed to adjust their bid, but only before the predefined time (e.g.,10:30 A.M. on the day before participation in the day ahead market).

At a predefined time on the bidding day (e.g., 1:30 P.M. on the daybefore the participation day), the bid may become locked and a day-aheadlocational marginal price (LMP) may be released by the RTO and/or ISO tothe customer. Further, the RTO and/or ISO may indicate which of theparticipation hours of the customer's bid have been approved. Theapproved hours may indicate hours that the customer is required toreduce their electric load based on their bid. If the customer does notreduce their electric load during the approved hours, the customer maybe subject to penalties.

The day-ahead LMP received by the customer indicates the price at whichthe customer will be compensated for the participation day. The revenuethat a customer can generate may be based on reductions in customer'selectric load, as committed in the customer's bid. This is illustratedby the piecewise function below. The piecewise function is shown toinclude term C_(DA) _(i) . C_(DA) _(i) may represent the amount ofrevenue that the customer generates during the participation day. Theterm P_(red) _(i) [kW] may represent the amount of power in kilowattsthat the customer has lowered their electric load (at an i^(th) hour)while the term r_(DA) _(i) [$/kWh] may represent the day-ahead LMP withunits of dollars per kilowatt hour (at an i^(th) hour). The value NBT(Net Benefits Test) is a threshold value that may have the same units asthe day-ahead LMP. In some cases, the value is referred to as a “NetBenefits Threshold” (NBT) which may be the same as the “Net BenefitsTest” (NBT) threshold. The NBT threshold may indicate a value at whichit is beneficial for the RTO and/or ISO to allow the customer toparticipate in the ELDR program. The NBT threshold may be a point on asupply curve, the NBT threshold may indicate where net benefits exceedsa load cost. The NBT threshold may indicate elasticity of one for thesupply curve. A customer may only be compensated for hours where the NBTthreshold is less than or equal to the day-ahead LMP. Comparing thesevalues may be referred to as a “Net Benefits Test.” The NBT thresholdmay be a value that any customer can access via a website of the RTO,ISO, and/or CSP. In some embodiments, the RTO, ISO, and/or CSP posts theNBT threshold on a website on the 15^(th) day of every month for thefollowing month.

$C_{DA_{i}} = \{ \begin{matrix}{P_{{red}_{i}}*r_{{DA}_{i}}} & {r_{{DA}_{i}} \geq {NBT}} \\0 & {otherwise}\end{matrix} $

Real-Time Market

The real-time ELDR market that the RTO and/or ISO may provide to thecustomer may allow a customer to place a bid for and participate in thereal-time ELDR market on the same day. The real-time ELDR market mayrequire the bid (e.g., a bid similar and/or the same as the bid of theday-ahead market) to be submitted to the RTO and/or ISO at least threehours before the top of the start of a participation hour. The ELDRprogram may allow a customer to participate in both the real-time ELDRmarket and the day-ahead ELDR market. In some embodiments, the RTOand/or ISO may require that a bid for the real-time ELDR market besubmitted before a predefined time on a day preceding the participationday (e.g., 6:00 P.M.) for a customer to be compensated for both thereal-time ELDR market and the day-ahead ELDR market.

A customer may be compensated for participation in the real-time ELDRmarket based on the NBT previously described above, the P_(red) _(i)amount previously described above, and a real-time LMP. In someembodiments, in the real-time market, a customer will be awardedparticipation hours, or there will be a high probability of beingawarded participation hours (e.g., 99%) if a customer bid includes acompensation rate that is greater than the NBT threshold. The real-timeLMP may be the amount at which a customer is compensated forparticipation in the real-time ELDR market.

The real-time LMP may be referred to herein as r_(RT) _(i) [$/kWh],specifically, in the piecewise equation below which may indicate thecompensation for participation in the real-time ELDR market. The termC_(RT) _(i) [$] below may indicate the amount by which a customer iscompensated for participating in the ELDR program. In the equationbelow, P_(red) _(i) [kW] may be the amount which the customer reducestheir electric load at hour i while C_(RT) _(i) may the amount at whicha customer is compensated at hour i.

$C_{RT_{i}} = \{ \begin{matrix}{P_{{red}_{i}}*r_{{RT}_{i}}} & {r_{{RT}_{i}} \geq {NBT}} \\0 & {otherwise}\end{matrix} $

In addition to receiving the revenue described with reference to theequation above, a customer may receive a “Make Whole Payment” (MWP). TheMWP may be a payment made for a segment when particular conditions aremet. The MWP may be available for a customer participating in either orboth of the day-ahead ELDR market and the real-time ELDR market. Theconditions may be that the electric load curtailment of the customer iswithin 20% of the bid electric load curtailment. The segments may becontiguous participation hours (e.g., 11 A.M. through 3 P.M.). In theequation below, the term C_(MWP_RT) _(i) [$] may represent the amountthat a customer is compensated for a MWP at an i^(th) hour. The valuev_(RT) _(i) [$] may represent the real-time load response bid at ani^(th) hour, v_(bal) _(i) [$] may represent a balancing synchronousreserve revenue above cost at an i^(th) hour, P_(disp) _(i) mayrepresent a real-time dispatched power at an i^(th) hour, the electricload that may be bid by the customer.

$C_{{MWP\_ RT}_{i}} = \{ \begin{matrix}{v_{{RT}_{i}} - v_{{bal}_{i}} - C_{{RT}_{i}}} & {r_{{bid}_{{RT}_{i}}} \geq {{NBT}\mspace{14mu}{and}\mspace{14mu}{{P_{{red}_{i}} - P_{{disp}_{i}}}}} \leq {0.2\; P_{{disp}_{i}}}} \\0 & {otherwise}\end{matrix} $

The term of the above equation, V_(RT) _(i) [$], may be calculated basedon the equation below. The equation below minimizes two power values(i.e., P_(disp) _(i) [$] and P_(red) _(i) described above) multiplied bya value, r_(bid_RT) _(i) . The value r_(bid_RT) _(i) may be a bid that acustomer had previously sent to the RTO and/or ISO, indicating the rateat which the customer wants to be compensated.

v _(RT) _(i) =min(P _(disp) _(i) _(,) P _(red) _(i) )r _(bid_RT) _(i)

The entire payment for a MWP segment may be illustrated by the followingequation. The term j may represent a particular segment while the term imay indicate a particular hour. The term C_(seg_MWP_RT) _(j) [$]represents compensation to the customer for the j^(th) segment MWP whilethe term C_(shutdown) [$] may be a shutdown cost that may be submittedin a customer bid. The shutdown cost may not be available ascompensation (e.g., the top term of the piecewise function below) if atleast one hour of a segment has an electric load reduction deviationthat is greater than 20% of the electric load bid (e.g., the powerdispatched by a utility).

$C_{{Seg\_ MWP}{\_ RT}_{j}} = \{ \begin{matrix}{{\max( {{{\sum_{i \in {Seg_{j}}}C_{{MWP\_ RT}_{i}}} + C_{shutdown}},0} )}\ } & \{ \begin{matrix}{r_{{bid\_ RT}_{i}} \geq {NBT}} \\{{{P_{{red}_{i}} - P_{{disp}_{i}}}} \leq {0.2P_{{disp}_{i}}{\forall{i \in {Seg}_{j}}}}}\end{matrix}  \\{{\max( {{\sum_{i \in {Seg_{j}}}C_{MWP_{{- R}T_{i}}}},0} )}\ } & \{ \begin{matrix}{r_{{bid\_ RT}_{i}} \geq {NBT}} \\{\exists{i \in {{{Seg}_{j}/{{P_{{red}_{i}} - P_{{disp}_{i}}}}} > {0.2P_{{disp}_{i}}}}}}\end{matrix}  \\{0\ } & {otherwise}\end{matrix} $

For both the real-time ELDR market and the day-ahead ELDR market, theremay be penalties if the customer fails to reduce their electric load bya proper amount. A balancing operating reserve (BOR) charge may be madeby the RTO and/or ISO for hours when the electric load reduced of acustomer deviates from the bid electric load (e.g., the power dispatchedby the utility) by more than 20%. In some cases, a customer may becharged two BOR penalties, that is, a “RTO BOR” and one of an “East BOR”deviation rate or an “West BOR” deviation rate. The “East BOR” and the“West BOR” deviation rates may be applied based on the location of thecustomer. A BOR may be defined by the equation below. In the equationbelow, the term BOR_(ch) _(i) [$] represents a BOR penalty at aparticular rate and hour. The term r_(BOR) _(i) [$/kWh] represents therate at which a customer is penalized for a particular hour, i. In somecases, one or more rates are applicable for a particular hour. In thesecases, several charges may be calculated and summed for that hour. Inmany cases, the rates are less than a dollar per megawatt hour ($/MWh).

${BOR}_{ch_{i}} = \{ \begin{matrix}{{{P_{{red}_{i}} - P_{{disp}_{i}}}}r_{{BOR}_{i}}} & {{{P_{{red}_{i}} - P_{{disp}_{i}}}} > {0.2P_{{disp}_{i}}}} \\0 & {otherwise}\end{matrix} $

Economic Load Demand Response (ELDR) Program Optimization

Referring now to FIG. 10, controller 1000 is shown in greater detail toinclude components configured to perform ELDR optimization, according toan exemplary embodiment. Controller 1000 may be the same and/or similarto energy storage controller 506 as described with reference to FIG. 6A,controller 552 as described with reference to FIG. 6B, and/or planningtool 702 as described with reference to FIG. 7. FIG. 10 is further shownto include incentive program 1012 and user device 1013 in communicationwith controller 1000. Incentive program 1012 may be a computer system orserver of an RTO, ISO, and/or CSP that is configured to allowcontrollers, e.g., controller 1000, to participate in an ELDR programthat the RTO, ISO, and/or CSP may provide. In some cases, incentiveprogram 1012 is a CSP that handles bidding and settlements for a RTO.User device 1013 may be a user device such as a smartphone, a laptop, adesktop, a tablet, and/or any other kind of computing device. Thefunctions of controller 1000 with respect to participating in an ELDRprogram can be implemented by energy storage controller 506 and/orplanning tool 702.

Memory 610 is shown to include building status monitor 624, as describedwith further reference to FIG. 6. Building status monitor 624 is shownto provide information indicative of the electric load of a building(e.g., buildings 116) to baseline generator 1002 and load/rate predictor622, historical electric load information. In some embodiments, buildingstatus monitor 624 provides historical electric load information toload/rate load predictor 1016. Building status monitor 624, may be incommunication with a building management system. In some embodiments,building status monitor 624 communicates with building management system606 and receives electric load information from building managementsystem 606 (as shown in FIGS. 6A-6B). Based on the electric loadinformation that building status monitor 624 receives, building statusmonitor 624 can be configured to generate a log of electric loadinformation for a plurality of years, months, days, hours, minutes,seconds, etc. The stored electric load log may be the historicalelectric load information that building status monitor 624 provides tobaseline generator 1002 and load/rate predictor 622.

Load/rate predictor 622 is shown to include load predictor 1016. Loadpredictor 1016 can be configured to receive electric load informationfrom building status monitor 624. In some embodiments, load predictor1016 is configured to predict load information based on the historicalelectric load information received from building status monitor 624. Insome embodiments, the predicted load information indicates an electricload at a particular time in the future and/or a period of time in thefuture. In some embodiments, load predictor 1016 uses weather forecasts,load information and/or any other information that building statusmonitor 624 has logged, etc. Load/rate predictor 622 can be configuredto predict an electric load based on the methods disclosed in U.S.application Ser. No. 14/717,593 filed on May 20, 2015, the entirety ofwhich is incorporated by reference herein.

Load/rate predictor 622 is further shown to include locational marginalprice (LMP) predictor 1014. LMP predictor 1014 is shown to receiveinformation indicative of an LMP from incentive program 1012. In someembodiments, the LMP information includes one and/or both of a day-aheadLMP and a real-time LMP. The day-ahead LMP may be a price at whichcontroller 522 may be compensated for reductions in energy use at basedon participation in a day-ahead market, a ELDR market in which bids aresubmitted one day ahead of participation times. Similarly, the real-timeLMP may be a price at which controller 1000 is compensated forreductions in energy use for a real-time ELDR market, a market that doesnot require bids to be submitted a day ahead but rather on the same dayas participation. The day-ahead ELDR market and the real-time ELDRmarket are further illustrated above and elsewhere herein.

LMP predictor 1014 can be configured to generate a predicted LMP basedon an LMP received from incentive program 1012. LMP predictor 1014 canbe configured to generate a predicted day-ahead LMP and a predictedreal-time LMP. In some embodiments, LMP predictor 1014 stores a historyof LMPs received from incentive program 1012. In some embodiments, basedon the date, current weather, or other information, LMP predictor 1014can be configured to generate a predicted real-time LMP and a predictedday-ahead LMP. LMP predictor 1014 can be configured to predict areal-time LMP and/or a day-ahead LMP based on weather forecasts and/or ahistorical log of past LMPs. LMP predictor 1014 can be configured topredict the LMP (e.g., the real-time LMP and/or the day ahead LMP) basedon the methods disclosed in U.S. application Ser. No. 14/717,593 filedon May 20, 2015. In some embodiments, LMP predictor 1014 uses astochastic model to predict LMPs. For example, LMP predictor 1014 mayuse a prediction model and may train the prediction model to generate anLMP model based on historical LMPs to determine coefficients for themodel. LMP predictor 1014 can be configured to provide the predicted LMPto participation predictor 1004. In this example, LMP predictor 1014 maypredict that an LMP for a weekday is the LMP for the most recentlyoccurring weekday. Similarly, for a weekend, the LMP for the weekend maybe the LMP for the most recently occurring weekend.

LMP predictor 1014 can be configured to generate a predicted LMP foreach hour of a future day. For example, for one particular day in thefuture (e.g., the next day), LMP predictor 1014 can be configured todetermine a predicted real-time LMP and a predicted day-ahead LMP ateach hour of the day. The LMPs can be provided by LMP predictor 1014 toparticipation predictor 1004. In this regard, the LMPs may be a vectorof length 24, with an LMP value for each hour indicated by an index,e.g., 1-24. In some embodiments, LMP predictor 1014 can be configured togenerate a predicted LMP for a plurality of days (e.g., for anoptimization period that is a plurality of days). For example, LMPpredictor 1014 can be configured to generate a predicted LMP for a weekin the future, a month in the future, and/or a year in the future.

Incentive program module 912 can be configured to cause controller 1000to participate in an ELDR program offered by incentive program 1012.Incentive program module 912 can be configured to receive LMPs fromincentive program 1012 (e.g., a real-time LMP and a day ahead LMP) andreceive a NBT threshold from incentive program 1012. Based on thisinformation and electric load information, incentive program module 912can be configured to generate a bid and send the bid to incentiveprogram 1012. The bid may include participation hours, a curtailmentamount, and a bid amount. The bid amount may be a rate of compensation(e.g., $/kWh). Incentive program module 912 can be configured to receiveawarded hours from incentive program 1012, awarded to incentive programmodule 912 based on the bid provided to incentive program 1012. Duringthe awarded hours, incentive program module 912 can be configured tocause HVAC equipment to operate to meet the curtailment amount of thebid.

Incentive program module 912 can generate a bid (or modify a bid) at aparticular interval. The interval may be once every 15 minutes, onceevery hour, or once every day. In some embodiments, incentive programmodule 912 generates a single bid for participating in the ELDR programwhen incentive program 1012 releases a day-ahead LMP. The bid mayindicate decisions made by the incentive program module 912 regardingwhen to participate in the ELDR program (e.g., what hours of an eventday or optimization period to participate in the ELDR program) and theamount that incentive program module 912 determines it will curtail anelectric load (e.g., grid load) by. This may be at a particular time(e.g., after 1:30 P.M.).

Incentive program module 912, described with reference to FIG. 9, isshown in FIG. 10 to include baseline generator 1002. Baseline generator1002 can be configured to generate a CBL based on participation hours, apredicted electric load, and historical electric load information. Insome embodiments, baseline generator 1002 communicates withparticipation predictor 1004 to determine an event start hour and anevent end hour for participation in the ELDR program. In this regard,participation predictor 1004 may generate participation hours and usethe participation hours as a search space to determine an event starthour and an event end hour. In this regard, baseline generator 1002 canbe configured to generate a CBL value for a plurality of hours so thatparticipation predictor 1004 can determine an event start hour and anevent end hour.

Baseline generator 1002 can be configured to receive historical electricload information from building status monitor 624. The historicalelectric load information may indicate an electric load of a building(e.g., buildings 116), campus (e.g., campus 12), a central plant (e.g.,central plant 118), and energy generation equipment (e.g., energygenerator 120) (at one or more times on one or more days (e.g., hourlyelectric load, electric load for a day, average electric load for a day,etc.). Baseline generator 1002 is further shown to be configured toreceive a predicted load from load predictor 1016. The predicted loadmay predict a load in the future e.g., on a day that controller 522 willbe participating in an ELDR program.

Baseline generator 1002 can be configured to generate a same-day CBLand/or an SAA CBL and provide the generated CBL to participationpredictor 1004. For an SAA CBL, baseline generator 1002 can beconfigured to generate a weekday SAA CBL or a weekend/holiday CBL. Thedifferences between the weekday SAA CBL, the weekend/holiday CBL, andthe same-day CBL are described below in Table 1.

A CBL may be the threshold from which incentive program 1012 determineshow much a customer (e.g., controller 1000) has reduced their electricload for each participation hour. For this reason, customers may becompensated by incentive program 1012 based on the CBL for particularparticipation days. The CBL may be a baseline for one particularparticipation day i.e., a CBL may change day to day. Generally, the CBLcan be based on the hour at which participation ends and/or starts.

In Table 1, the differences between an SAA and a same-day CBL areillustrated. As can be seen, there are two different types of SAA CBLs,a weekday SAA CBL and a weekend/holiday SAA CBL. If the participationday falls on a weekday, the weekday SAA CBL may be appropriate while ifthe participation day falls on a weekend/holiday then theweekend/holiday SAA may be applicable.

TABLE 1 Differences in parameters between SAA and same-day CBL ParameterSAA Same Day Day Type Weekday Weekend/Holiday N/A Calculation AverageAverage Average CBL Basis Days 5 3 N/A CBL Basis Day Limit 45 45 N/AStart Selection From X X = 1 X = 1 N/A Days Prior To Event ExcludePrevious Yes Yes N/A Curtailment Days? Exclude Long and Short N/A YesN/A Daylight Saving Time (DST) Days Exclude Average Event Threshold =25% Threshold = 25% N/A Period Usage Less Than A Threshold Exclude XNumber Of X=1 X=1 N/A Low Usage Days Use Previous Curtailment Yes YesN/A If CBL Basis Window Is Incomplete Use Highest Or Recent HighestHighest N/A Previous Curtailment Day Adjustments SAA SAA None AllowNegative Yes Yes N/A Adjustments Adjustments Start (HEO- X = 4 X = 4 N/AX) Number Of Adjustment 3 3 N/A Basis Hours

For all three types of CBLs, the CBLs may be determined based on anaverage calculation. For the SAA CBLs, there may be a 45 day window(days prior to a participation day) for selecting days to use ingenerating the CBL (e.g., determining an average). Further, for the SAACBLs, the days selected for generating the CBL may be at least one dayprior to the participation day. For SAA CBLs, any participation days maybe excluded from use in generating the CBL.

For weekend/holiday SAA CBLs, any days which are daylight saving timedays may be excluded from use in generating a weekend/holiday SAA CBL.For both the weekday and weekend/holiday SAA CBLs, a threshold of 25%may be used in removing particular days from use in generating the SAACBL. This is described in further detail below. When generating theweekday or weekend/holiday SAA CBLs, one lowest energy loadparticipation day may be removed from use in generating the weekday orweekend/holiday SAA CBL. This is also further described below.

In the event that no days are available in the 45 day window for use ingenerating an SAA CBL, for the both weekday and the weekend/holiday SAACBLs, days that include participation in the ELDR program may be used ingenerating the SAA CBL. The participation days used may be the highestelectric load days that include participation in the ELDR program. Forboth SAA CBLs, Table 1 indicates that a particular offset may be used inthe SAA CBL, an SAA offset. Table 1 further indicates that this offsetmay be negative. For a same-day CBL, there may be no offset. Theadjustment may be determined based on hours starting four hours beforethe beginning of participation in the ELDR program. For an SAA CBL,three hours may be used in calculating the SAA adjustment.

Baseline generator 1002 can be configured to generate a customerbaseline load (CBL). Baseline generator 1002 can be configured togenerate an SAA baseline and/or a same day baseline. In someembodiments, a user may indicate via user device 1013, a selection ofSAA or same-day baseline. Based on the selection, baseline generator1002 can be configured to generate a CBL indicative of the selected CBLtype. In some embodiments, baseline generator 1002 receives a selectionof CBL type from incentive program 1012. In this regard, baselinegenerator 1002 can be configured to generate a CBL based on the CBL typeindicated by the selection of the incentive program 1012. In someembodiments, incentive program 1012 determines which baseline should beused by controller 1000. Incentive program 1012 may provide a user witha tool (e.g., web tool) to determine which type of CBL (i.e., SAA CBL orsame-day CBL) is applicable for a particular customer.

Same Day CBL

Baseline generator 1002 can be configured to generate a same day CBLbased on a predicted load received from load predictor 1016 and/orparticipation hours received from participation predictor 1004. Thepredicted load information may indicate the electric load of a building(e.g., buildings 116) at various hours, minutes, seconds, days, weeks,months, etc. in the future.

Baseline generator 1002 can be configured to use the equation below togenerate a same day CBL. The same-day CBL may be an average of threehours one hour prior to the first hour of participation and two hoursone hour after participation. In some embodiments, baseline generator1002 can be configured to use the equation below to generate a same-dayCBL. In the equation below, e_(CBL,k) represents the same-day CBL. Thevalues ES and EE represent a starting hour (ES) and an ending hour (EE)for the time period of participation in the ELDR program (e.g., thefirst hour of participation and the last hour of participation in aparticipation day). The starting hour and the ending hour may be thestarting and ending hours of the participation hours received fromparticipation predictor 1004. In some embodiments, participationpredictor 1004 provides baseline generator 1002 with ES and EE hours ofthe participation hours in order to “search” the participation hours forhours that are optimal.

The term e_(i) may be the electric load during the i^(th) hour. In someembodiments, e_(i) is predicted electric load value received from loadpredictor 1016. Similarly, e_(j) may be a value indicative of thepredicted electric load of building (e.g., buildings 116) during thej^(th) hour. In some embodiments, e_(j) is a predicted load valuereceived from load predictor 1016.

$e_{{CBL},k} = {{\frac{{\sum_{i = {{ES} - 4}}^{{ES} - 2}e_{i}} + {\sum_{j = {{EE} + 2}}^{{EE} + 3}e_{j}}}{5}\mspace{31mu}{\forall k}} = {1\mspace{14mu}\ldots\mspace{14mu} 24}}$

Incentive program module 912 can be configured to not participate in theearliest three hours of a day and the last two hours in the day. Thismay be a rule set by incentive program 1012 to make sure that there areenough hours to be used by baseline generator 1002 to generate thesame-day CBL. For this reason, the ELDR program may not allow a customerto participate in the first three hours of a day and the last two hoursof a day to make sure that a same day CBL can be calculated for any day.The same day CBL may be a constant CBL, i.e., the CBL may be the samefor every participation hour. This is illustrated in FIG. 13 where thesame day CBL is shown as a horizontal line.

Baseline generator 1002 can be configured to generate an SAA CBL. An SAACBL may be a CBL that is a standard tariff defined CBL which may beapplicable for most non-variable economic demand resources. Baselinegenerator 1002 can be configured to generate the SAA CBL based onelectric load information received from building status monitor 624. Insome embodiments, baseline generator 1002 stores electric loadinformation received from building status monitor 624 and predicted loadinformation received from load predictor 1016 and uses the electric loadinformation and the predicted load information to generate the SAA CBL.

Baseline generator 1002 can be configured to generate an SAA CBL basedon the day which the participation in the ELDR program occurs. Baselinegenerator 1002 can be configured to determine if the participation timein the ELDR program occurs on a weekday or a weekend and/or holiday andgenerate an SAA CBL based on whether the participation in the ELDRprogram falls on a weekday, weekend, or holiday (i.e., generate aweekday SAA CBL or a weekend/holiday CBL).

The SAA CBL may average a different number of days based on what type ofday (e.g., weekday, weekend, or holiday), participation in the ELDRprogram occurs (see Table 1, CBL Basis Days). If the day thatparticipation in the ELDR program occurs is a weekday, baselinegenerator 1002 can be configured to average four days with the highestelectric load out of five days that are the most recent weekdays inwhich controller 1000 has not participated in the ELDR program. If theday that participation in the ELDR Program occurs is a weekend orholiday, baseline generator 1002 can be configured to average twoweekends or holidays with the highest electric load out of the threemost recently occurring weekend or holiday days in which controller 1000has not participated in the ELDR program (see Table 1, Exclude X NumberOf Low Usage Days).

Weekday SAA CBL

The description below is an example of determining a weekday SAA CBL bybaseline generator 1002. Baseline generator 1002 can be configured togenerate a weekday SAA CBL based on the equations illustrated below. Theequation immediately below may indicate the five most recently occurringdays with no participation in the ELDR program. Baseline generator 1002can be configured to identify these five week days when theparticipation day is a weekday and three weekends or holidays when theparticipation day is a weekend or holiday. For this example, theparticipation day is a weekday and the term D is the set of weekdays(excluding weekday holidays), i.e., d₁, d₂, d₃, d₄, d₅. These days maybe days that controller 1000 has not participated in the ELDR programand that are the most recently occurring weekdays. Baseline generator1002 may store a historical log of weekdays, weekends, and holidays. Thelog may indicate whether a particular day included participation in theELDR program. Baseline generator 1002 can be configured to retrieve thefive most recent non-participation days from the historical log.

D={d ₁ ,d ₂ ,d ₃ ,d ₄ ,d ₅}

Baseline generator 1002 can be configured to receive electric loads fora plurality of days and hours for the past from building status monitor624. The equation below indicates the hours of each day of the set ofdays above, where d_(i) is an hourly load vector. Thus, the followingequation can represent the electric load for each hour of a day, i.e.,for each day of the set of days in the above equation. In the followingequation, the day term, d_(i), may be a day with a set of electric loadsat each hour of an i^(th) day. The term e_(ij) may represent theelectric load on the i^(th) day at the j^(th) hour which may be anelectric load received from building status monitor 624.

d _(i)=[e _(i1) . . . e _(i24)]

Baseline generator 1002 can be configured to generate a daily averageevent period electric load for each day of the set of days, D. Baselinegenerator 1002 can be configured to use the equation below to generatethe daily average for each day. For a particular day that controller1000 is participating in the ELDR program, baseline generator 1002 canbe configured to generate a daily average event period electric load. Inthe equation below, the term d ₁ represents the daily average eventperiod electric load. The term k ∈ participation represents theparticipation hours of the day that controller 1000 will beparticipating in the ELDR program, the participation hours received fromparticipation predictor 1004. These hours may not need to be contiguous.The term n may represent the total number of hours that that controller1000 will be participating in the ELDR program (e.g., the total numberof participation hours received from participation predictor 1004). Thismay cause the daily average event period electric load to be based onhours that controller 1000 will be participating in the ELDR program.

${{\overset{\_}{d}}_{i} = {{\sum\limits_{k \in {{participati}\;{on}}}{\frac{e_{ik}}{n}{\forall i}}} = 1}},\ldots\mspace{14mu},5$

After determining the daily average event period electric load, baselinegenerator 1002 can be configured to average the daily average eventperiod electric load for each of the five days of the set of days, D.The term D represents the average of each daily average event periodelectric load, d _(i).

$\overset{\_}{D} = {\sum\limits_{i = 1}^{5}\frac{{\overset{\_}{d}}_{i}}{5}}$

After determining the average D, baseline generator 1002 can beconfigured to remove days from the set of days, D. Baseline generator1002 can be configured to use the relationship, d _(i)<0.25×D to removedays from the set of days, D (see Table 1 for 0.25, Exclude AverageEvent Period Usage Less Than A Threshold). If any of the days d _(i)meets the requirement of the relationship, those days are removed fromthe set of days, D, and the most recent non-event day is used todetermine D a second time. In some embodiments, baseline generator 1002only uses the most recent non-event days that occur 45 days before theday which controller 1000 is participating in the ELDR program. Baselinegenerator 1002 can perform as many iterations of this process asnecessary until all of the days of the set of days D are greater and/orequal to, 0.25×D.

Once, the set of days D is finally determined by baseline generator1002, baseline generator 1002 can be configured to determine an hourlyaverage of four of the five days, the four days having the highestelectric loads. If baseline generator 1002 cannot determine five daysthat do not meet the condition d _(i)<0.25×D 45 days prior to the daythat controller 1000 will be participating in the ELDR program but canonly find four days, baseline generator 1002 can average the four daysand may not exclude any days from the average. If baseline generator1002 only finds three or less days that do not meet the criteria withinthe forty five day window, then baseline generator 1002 can beconfigured to select the most recent event day (i.e., a day in whichcontroller 1000 participated in the ELDR program) and use the event dayin the determination of the CBL. These event days may be the highestelectric load event days of the last 45 days. Baseline generator 1002can be configured to use event days so that the set of days, D, has atleast four days that do not meet the criteria d _(i)<0.25×D.

The following equation can be used by baseline generator 1002 togenerate a preliminary CBL. The preliminary CBL may be an hourly averageof the four days of five days that do not meet the criteria d_(i)<0.25×D. The four days may be days that make the relationshipi≠arg_(i) min(d _(i)) true, i.e., the four days do not make d _(i) be aminimum. In the equation below, the term ē_(j) represents the hourlyaverage for a plurality of hours.

${\overset{\_}{e}}_{j} = {{\sum\limits_{i}{\frac{e_{ij}}{4}\mspace{31mu} i}} \neq {\arg_{i}{\min( {\overset{\_}{d}}_{i} )}}}$

Baseline generator 1002 can be configured to offset the preliminary CBLto determine the CBL, the “standard CBL” (e.g., the CBL that baselinegenerator 1002 provides to participation predictor 1004). The standardCBL is represented by the term e_(CBL) below which is a set of CBLvalues for each hour of a day.

e _(CBL)=[e _(CBL,1) . . . e _(CBL,24)]

Baseline generator 1002 can be configured to generate the CBL byoffsetting the preliminary CBL, ē_(j), with an SAA value, e_(SAA).

e _(CBL,j) =ē _(j) +e _(SAA)

Baseline generator 1002 can be configured to determine e_(CBL,j) byfirst determining the SAA value, e_(SAA). The equation below illustratesone method that baseline generator 1002 can be configured to use todetermine e_(SAA). In the equation below, the term EE may represent thestarting hour of participation in the ELDR program by controller 1000while ES may represent the ending hour of participation in the ELDRprogram (e.g., the hours defined by the participation hours). The timebetween EE-2 and ES-4 may represent the SAA hours (e.g., SAA hours 1406of FIG. 14). The term e_(0k) may represent the electric load at thek^(th) hour of the participation day while the value ē_(k) may representthe average electric load over the hour. The values e_(0k) and ē_(k) maybe and/or be based on predicted load information received from loadpredictor 1016. In some embodiments, the values e_(0k) and ē_(k) aredetermined by baseline generator 1002 based on the predicted loadinformation received from load predictor 1016.

$e_{SAA} = {\sum\limits_{k = {{ES} - 4}}^{{EE} - 2}\frac{e_{0k} - {\overset{\_}{e}}_{k}}{3}}$

It should be noted that the electric load during the SAA hours, i.e.,between ES-4 and EE-2, impact the CBL, e_(CBL) such that a high electricload during the SAA hours results in a higher baseline. Thus, increasingthe curtailment amount and increasing the revenue from participation inthe ELDR program. Similarly, a low electric load during the SAA hoursresults in a lower baseline, thus decreasing the amount reduced anddecreasing revenue earned in the participation in the ELDR program. Forthis reason, incentive program 1012 may have rules in place thatprohibit controller 1000 from artificially raising the electric load ofbuilding (e.g., buildings 116) during the SAA hours to artificiallyincrease the CBL and thus increase revenue. Incentive program 1012 mayuse a plurality of rules to determine whether controller 1000 abnormallyraised the electric load during the SAA hours and may reject settlementswith controller 1000 where controller 1000 artificially raised theelectric load. However, incentive program 1012 may allow controller 1000to increase an electric load during the SAA in response to energy pricechanges without penalizing (i.e., rejecting a settlement) controller1000.

Weekend/Holiday SAA CBL

Baseline generator 1002 can be configured to generate weekend/holidaySAA CBL. Baseline generator 1002 can be configure to generate theweekend/holiday SAA CBL based on the electric load information receivedfrom building status monitor 624 and the predicted load informationreceived from load predictor 1016. Baseline generator 1002 may generatethe weekend/holiday SAA CBL in the same way as it generates the weekdaySAA CBL. However, baseline generator 1002 can be configured to use thethree most recent Saturdays, Sundays, or Holidays that are not days thatcontroller 522 has participated in the ELDR program as opposed to usingweekdays. Of the three days selected by baseline generator 1002 forgenerating a weekend/holiday SAA CBL, baseline generator 1002 may usetwo of the three days with the highest electric load, in the same waythe baseline generator 1002 uses four of the five days of the set D whengenerating a weekday CBL. The baseline generator 1002 may be configuredto not use any Saturday, Sunday, or Holiday that falls on a daylightsavings time day (e.g., the day begins a daylight savings time period orends a daylight savings time period) (e.g., clocks are shifted backwardor forward at the beginning or the ending of the day).

Incentive program module 912 is shown to include participation predictor1004. Participation predictor 1004 is shown to receive the CBL frombaseline generator. Further, Participation predictor 1004 is shown toreceive a predicted LMP from LMP predictor 1014 (e.g., a predictedday-ahead LMP and a predicted real-time LMP). Participation predictor1004 can be configured to generate participation hours. Participationpredictor 1004 can be configured to provide selector 1008 with theparticipation hours.

Participation predictor 1004 can be configured to generate and/ordetermine (e.g., predict) participation hours. In some embodiments, theparticipation hours are a vector or mask (e.g., a participation mask) ofones and zeros. The participation hours may represent a full day, e.g.,the participation mask may include twenty four total ones and zeroswhere a one represents participation and a zero represents noparticipation at a particular hour. The participation hours are providedto selector 1008. Participation predictor 1004 can further be configuredto provide the participation hours to baseline generator 1002.Participation predictor 1004 can be configured to use the CBL receivedfrom baseline generator 1002 to further determine the participationhours.

Participation predictor 1004 can be configured to set all hours of theparticipation hours to 0 (e.g., all hours of a particular day to noparticipation), indicating no participation in any of the hours. Basedon a NBT threshold value received from incentive program 1012, thepredicted LMPs received from LMP predictor 1014, and/or a CBL receivedfrom baseline generator 1002, participation predictor 1004 can beconfigured to select hours that controller 1000 will participate in theELDR program. In some embodiments, incentive program module 912retrieves the NBT threshold value once every month after the 15^(th) ofthe month from incentive program 1012, the NBT threshold being the NBTthreshold for the next month. In some embodiments, participationpredictor 1004 may set none, one, some, or all of the participationHours to 1, indicating participation except hours restricted byincentive program 1012 (e.g., hours restricted by incentive program 1012based on CBL type).

Participation predictor 1004 can be configured to compare the predictedday-ahead LMP and the predicted real-time LMP for each hour of a day tothe NBT threshold value to determine if the associated hour should be aparticipation hour. The steps below illustrate steps that participationpredictor 1004 can be configured to perform to determine theparticipation hours. These steps are further illustrated in FIG. 11A. Insome embodiments, only one of the conditions of steps 1104 and 1106 needto be true to set an hour to participation. Participation predictor 1004can be configured to perform steps 1102-1112 to generate theparticipation hours or only perform steps 1102-1108 to generate theparticipation hours. The participation mask generated by participationpredictor 1004 can be provided to selector 1008. The participation hoursmay be the hours where p_(i)=1.

Referring now to FIG. 11A, a process 1100 for determining participationhours and transmitting a bid to incentive program 1012 is shown,according to an exemplary embodiment. Controller 1000 and the variouscomponents of controller 1000 can be configured to perform process 1100.Further, energy storage controller 506, controller 552, and/or planningtool 702 can be configured to perform process 1101. In some embodiments,planning tool 702 may not send any bid to incentive program 1012 i.e.,may not perform step 1120 of process 1100. In some embodiment,participation predictor 1004 can be configured to perform steps1102-1108 or steps 1102-1112 of process 1100 to generate theparticipation hours based only on the NBT threshold and not on the CBL.

-   -   Step 1102: Set all participation hours to no participation,        i.e., initialize a participation mask p_(i) and set p_(i)=0        -   Step 1104: Set p_(i)=1 where r_(DA) _(i) ≥NBT        -   Step 1106: Set p_(i)=1 where r_(RT) _(i) ≥NBT    -   Step 1108: The participation hours are the hours where the        conditions in Step 1104 or Step 1106 are true

In step 1102, participation predictor 1004 can set all participationhours to zero or otherwise to no participation. In some embodiments, theparticipation hours are represented by a participation mask, p_(i). Theparticipation mask may be a vector of ones and zeros which indicateeither participation or no participation at various hours of anoptimization period (e.g., a day). In step 1118, participation predictor1004 can initialize the participation mask and set the entireparticipation mask to zero (e.g., all hours of the participation mask tozero).

In steps 1104 and 1106, participation predictor 1004 can determine thatthe participation hours are hours where the predicted day-ahead LMPreceived from LMP predictor 1014 is greater than the NBT threshold orthe predicted real-time LMP received form the LMP predictor 1014 isgreater than the NBT threshold. In some embodiments, process 1100 mayinclude one or both of steps 1104 and 1106. In this regard, theparticipation hours may be based on the predicted real-time LMP and/orthe day ahead LMP. In step 1108, participation predictor 1004 candetermine that the participation hours are the hours where theconditions of step 1104 or 1106 are true.

In some embodiments, participation predictor 1004 can be configured toperform steps 1102-1112 to generate the participation hours. Thisapproach may assume a constant maximum energy reduction.

-   -   Step 1102: Set all participation hours to no participation,        i.e., initialize a participation mask p_(i) and set p_(i)=0    -   Step 1104-1108: Determine that the participation hours are hours        where r_(DA) _(i) ≥NBT or r_(RT) _(i) ≥NBT are true        -   Step 1110: Determine ES and EE from the equation:

$\min\limits_{{ES},{EE}}( {- {\sum\limits_{i = {ES}}^{EE}{{\overset{\hat{}}{r}}_{RT_{i}}( {e_{{CBL},i} - {\max( {( {{\overset{\hat{}}{e}}_{i} - P_{\max}} ),P_{{gridLim}\;{it}}} )}} )}}} )$with  p_(i)  as  search  hours

-   -   -   Step 1112: The participation hours are the hours between the            determined ES and EE

In steps 1102-1108 above, participation predictor 1004 can determinehours that participation is allowed. These hours may act as a searchspace for step 1110. The search hours may be provided by participationpredictor 1004 to baseline generator 1002 for determining ê_(CBL,i) inorder to determine ES and EE which are used to refine the participationhours.

In step 1110, participation predictor 1004 can minimize the equationwith the participation hours determined in steps 1120-1124. The equationof step 1126 is shown to be dependent on a CBL, a predicted electricload, and a real-time LMP. Further, the equation is dependent onP_(gridLimit) and P_(max). Minimizing the equation can maximizepotential revenue from participating the in ELDR program. The term,ê_(CBL,i) may be a CBL determined by baseline generator 1002. This maybe a CBL for a plurality of hours based on the search hours determinedin steps 1104-1108. The CBL is a function of the event start, ES, andevent end, EE hours. The CBL may be a CBL for a plurality of hours,e.g., the i^(th) hours. In some embodiments, the CBL is an SAA CBL, inother embodiments, the CBL is a same-day CBL. The term {circumflex over(r)}_(RT) _(i) may be a real-time predicted LMP received from LMPpredictor 1014 for a plurality of hours, e.g., the i^(th) hours whiler_(DA) _(i) may be a day-ahead predicted LMP received from LMP predictor1014 for a plurality of hours, e.g., the i^(th) hours

Further, the ê_(i) term may represent a predicted electric load. Thepredicted electric load may be received from load predictor 1016.Further, the equation of step 1110 is shown to include terms P_(max) andP_(gridLimit). These may be constant values stored by participationpredictor 1004. In some embodiments, P_(max) is a customer based value.This amount may indicate the maximum amount a customer can reduce theirelectric load by. P_(max) may be based on equipment of a customer. Forexample, a value for P_(max) may be 12 MW for a customer that has twoco-gens. In some embodiments, P_(gridLimit) is a value received from autility. The value P_(gridLimit) may be a minimum imposed on thecustomer by the utility. In some embodiments, P_(max) and P_(gridLimit)are constants over all hours. In various embodiments, P_(max) andP_(gridLimit) are hourly values. Based on the ES and the EE valuesdetermined by participation predictor 1004, participation predictor 1004can determine, in step 1112, that the participation hours are betweenthe ES and the EE hours.

Referring again to FIG. 10, selector 1008 can be configured to receivethe participation hours from participation predictor 1004. Selector 1008can be configured to further receive user hours from user device 1013.Selector 1008 can be a component that can be configured to selectbetween user hours and participation hours. User hours may have apriority above the participation hours. When selector 1008 receives userhours but does not receive participation hours, selector 1008 can beconfigured to output participation hours as user hours, regardless ofthe participation hours received from participation predictor 1004. Ifselector 1008 does not receive user hours, selector 1008 can beconfigured to output the participation hours received from participationpredictor 1004.

Selector 1008 can be configured to provide cost function modifier 1010and bid controller 1006 with participation hours. Bid controller 1006can be configured to receive participation hours from selector 1008 andload information from cost function modifier 1010. Based on the loadinformation and the participation hours, bid controller 1006 can beconfigured to generate a bid to send to incentive program 1012.

Bid controller 1006 can be configured to generate a bid forparticipation in the ELDR program based on the participation hoursreceived from selector 1008 and send the bid to incentive program 1012.In some embodiments, bid controller 1006 is configured to refine theparticipation hours by determining, based on a CBL, whether aparticipation hour received from selector 1008 should be included in abid. In some embodiments, the CBL is determined by bid controller 1006based on the participation hours and an electric load received from costfunction modifier 1010, Since bid controller 1006 can be configured togenerate a CBL for the participation hours it receives, bid controller1006 may include an instantiation of baseline generator 1002 and/or mayotherwise include all of the functionality of baseline generator 1002.

Referring again to FIG. 11A, bid controller 1006 can be configured toperform steps 1114-1120. Bid controller 1006 can send bids to incentiveprogram 1012 based on the rules of the ELDR program as described above.Bid controller 1006 can perform steps 1114-1120 of process 1101 togenerate a bid and send the bid to incentive program 1012.

-   -   Step 1114: Determine a CBL based on the participation hours    -   Step 1116: Subtract the load from the CBL values for the        participation hours    -   Step 1118: Remove participation hours where the difference is        less than or equal to zero    -   Step 1120: Transmit a bid to an incentive program

In step 1114, bid controller 1006 can calculate CBL values for each hourof the participation hours received from selector 1008. Bid controller1006 is shown in FIG. 10 to include an instantiation of baselinegenerator 1002. In this regard, bid controller 1006 can use theparticipation hours received from selector 1008 and baseline generator1002 to generate the CBL. In some embodiments, bid controller 1006 usesthe participation hours to determine a CBL for each hour of theparticipation hours. Bid controller 1006 can use the CBL it generatesand the participation hours to determine CBL values for theparticipation hours.

In step 1116, bid controller 1006 can subtract the load received fromcost function modifier 1010 for each hour of the participation hoursfrom the CBL load values. This may be the curtailment amount. In 1118,in response to determining that the difference is less than or equal tozero for a particular hour, bid controller 1006 can remove that hourfrom the participation hours. In step 1120, based on the modifiedparticipation hours (or unmodified participation hours), bid controller1006 can transmit a bid to incentive program 1012 indicative of theparticipation hours and/or the curtailment amount at each participationhour (e.g., a baseline amount minus the load received from cost functionmodifier 1010).

Referring again to FIG. 10, based on the bid transmitted by bidcontroller 1006 to incentive program 1012, incentive program 1012 can beconfigured to approve or reject the bid. Any hours that incentiveprogram 1012 determines are appropriate may be transmitted toparticipator 1018 as awarded hours. These may be hours that controller1000 may be required to reduce the electric load of building (e.g.,buildings 116) based on the electric load and/or the electric loadreduction for each hour of the awarded hours that was originallytransmitted to incentive program 1012 via bid controller 1006.

Participator 1018 can be configured to receive the awarded hours fromincentive program 1012 and further receive an electric load for eachawarded hour from cost function modifier 1010 (or from high leveloptimizer 632). The awarded hours may indicate hours that controller1000 must participate in the ELDR program at a particular electric loadamount. These may be hours that controller 1000 cannot change a decisionto participate or not participate in the ELDR program. In someembodiments, the awarded hours can be changed if the controller 1000adjusts or otherwise changes a bid. Participator 1018 can be configuredto cause HVAC equipment to operate to meet the electric loads during theawarded hours. In some embodiments, the HVAC equipment includesbatteries, co-gens, lighting systems, gas turbines, chillers, airhandlers, and/or any other piece of HVAC or building equipment thatconsumes electricity as described herein or known in the art.

High level optimizer 632 is shown to include cost function modifier1010. Cost function modifier 1010 can be configured to modify a costfunction that high level optimizer 632 can be configured to generate.The cost function (e.g., cost function module 902), further described inFIG. 9 may be a cost function that includes costs and benefits fromoperating various subplants and participating in various programs, e.g.,a frequency regulation program and/or an ELDR program. As describedelsewhere herein, the cost function may be in the form of the followingequation.

${J(x)} = {{\sum\limits_{sources}{\sum\limits_{horizon}{{cost}( {{{pur}{cha}\;{se}_{{resource},{time}}},{time}} )}}} - {\sum\limits_{incentives}{\sum\limits_{horizon}{{revenue}({ReservationAmount})}}}}$

As described elsewhere herein, the cost function can be optimized basedon various constraints. These constraints may be the constraintsillustrated below and/or elsewhere herein. These constraints may balancebetween resources purchased, produced, discharged, consumed, andrequested over an optimization period.

${{{\sum\limits_{sources}{purchase_{{resource},{time}}}} + {\sum\limits_{{sub}\;{plants}}{produce{s_{resource}( {x_{{subplants},{{inte}\;{rnal}\mspace{11mu}{decision}},{time}},x_{{externaldecision},{time}},{{uncontrolled}\mspace{14mu}{variable}_{time}}} )}\mspace{14mu}\ldots}} - {\sum\limits_{{sub}\;{plants}}{consume{s_{resource}( {x_{{{subpl}\;{ant}},{{interna}\;{ldecision}},{time}},x_{{externaldecision},{time}},{{uncontrolled}\mspace{14mu}{variable}_{time}}} )}\mspace{14mu}\ldots}} + {\sum\limits_{storages}{discharge{s_{resource}( {x_{{storage},{{internalde}\;{cision}},{time}},x_{{externaldecision},{time}}} )}}} - {\sum\limits_{sinks}{requests_{resource}}}} = {0\mspace{11mu}{\forall{resources}}}},{\forall{{time} \in {{horizon}.}}}$

Cost function modifier 1010 can be configured to generate a term for thecost function, the ELDR term. The ELDR term may have the followingformat, where k is the length of an optimization period hours (e.g., 24for a full day), k is an instant in time of the optimization period(e.g., 1, 2, 3 . . . 24 for each hour of a day), his the length of theoptimization period, p_(i) includes the participation hours (e.g.,either 1 or 0) for each hour, e_(CBL,i) is the value of CBL at each timeinterval, and e_(i) is the electric load at each time interval (e.g., ateach hour) of the optimization period. In some embodiments, the CBL is aCBL received from bid controller 1006 that is a CBL based on theparticipation hours. In some embodiments, cost function modifier 1010includes some and/or all of the functionality of baseline generator 1002and can be configured to generate a CBL based on the participation hoursreceived from selector 1008. The term {circumflex over (r)}_(RT) _(i)may be the predicted real-time LMP generated by LMP predictor 1014.

$- {\sum\limits_{i = k}^{k + h - 1}{p_{i}{{\overset{\hat{}}{r}}_{RT_{i}}( {e_{{CBL},i} - e_{i}} )}}}$

The cost function may have any number of terms, terms relating tovarious programs (e.g. other IBDR programs), resource consumption, etc.The cost function below highlights a cost function that includes an ELDRterm. The ELDR term can be added to the cost function by cost functionmodifier 1010, according to some embodiments. The term {circumflex over(r)}_(e) _(i) may be an actual electric rate at each instant in time ora predicted electric rate at each instant in time. The term e_(i) may beelectric load and may be a decision variable of the cost function thatcan be optimized for a plurality of hours by optimizing the costfunction. The cost function may include other decision variables, forexample, decision variables for battery allocation, chilled waterproduction, and/or any other decision variable. In this regard, theelectric load of the cost function may depend on other decisionvariables of the cost function.

$J = {{\sum\limits_{i = k}^{k + h - 1}{{\overset{\hat{}}{r}}_{e_{i}}e_{i}\mspace{14mu}\ldots}}\; - {\sum\limits_{i = k}^{k + h - 1}{p_{i}{{\overset{\hat{}}{r}}_{RT_{i}}( {e_{{CBL},i} - e_{i}} )}}}}$

The ELDR term may be a bilinear term since the term is a function ofboth the participation hours and the electric load. The bilinear costfunction can be solved using mixed integer linear programming (MILP).The cost function can be solved via a cascaded approach in someembodiments. In some embodiments, in order to solve the optimizationproblem using linear programming, it may be necessary to linearize theELDR term. Linearization can be achieved by making the assumption thatthe participation hours are known and are not part of the decisionvariables of the optimization problem. For this reason, participationpredictor 1004 can make a preliminary decision as to the participationhours and these hours are used by cost function modifier 1010. This maybe a cascaded approach to solving the optimization problem.

Cost function modifier 1010 (or high level optimizer 632) can beconfigured to linearize the cost function so that the cost function canbe optimized via linear programming or any other optimization. The costfunction above can be linearized into the following equation.

$J = {\sum\limits_{i = k}^{k + h - 1}{( {{\hat{r}}_{e_{i}} + a_{i}} )e_{i}}}$where a_(i) = f(r̂_(RT_(j))) < 0 ∀i ∈ CBL  hours/j ∈ Participation  Hours a_(i) = r̂_(RT_(j))∀i ∈ Participation  Hours a_(i) = 0  otherwise

It can be seen in the above equation that the term, a_(i), is anadjustment to the electric rate, {circumflex over (r)}_(e) _(i) . Forthis reason, it can be understood that participation in the ELDR programis the equivalent of a rate adjustment, an adjustment a_(i).Participation in the ELDR program may be represented in the costfunction as an electric rate adjustment. The electric rate adjustmentmay be an electric rate adjustment during participation hours and hoursused to determine a baseline. High level optimizer 632 can be configuredto determine an electric load for various hours based on the rateadjustment. In some embodiments, the participation hours are used bycost function modifier 1010 to determine the necessary electric rateadjustment during the participation hours and/or during the baselinehours. In some embodiments, the electric rate adjustment is a functionof the baseline, the participation hours, the predicted real-time LMPand/or the day-ahead LMP.

High level optimizer 632 can be configured to optimize the cost functionmodified by cost function modifier 1010. In some embodiments, theoptimization is based, at least in part, on the electric rateadjustment. In some embodiments, high level optimizer 632 can beconfigured to use linear programming to optimize the modified costfunction. In various embodiments, high level optimizer 632 uses variousconstraints when optimizing the modified cost function. High leveloptimizer 632 can be configured to use optimization algorithms (e.g.,linear programming, quadratic programming, etc.), iterative methods,global convergence, and/or heuristics and/or any other optimizationalgorithm or method to optimize the cost function. Optimization and thecost function are further described with reference to FIG. 9 andelsewhere herein. High level optimizer 632 can be configured todetermine a plurality of decision variables (e.g., e_(i), an electricload) and provide the electric load to bid controller 1006. Further,controller 1000 (e.g. participator 1018) can be configured to causebuilding equipment to be operated to meet the electric loads.

To illustrate the optimization, consider the following example. Costfunction modifier 1010 may receive participation hours for a 24 houroptimization period from selector 1008. The participation hours mayindicate participation in the ELDR program at the tenth hour of the daythrough the eighteenth hour of the day. The participation hours can berepresented by the vector p_(i), and is illustrated below.

$p_{i} = \{ \begin{matrix}1 & {{\forall i} = {10 - 18}} \\0 & {otherwise}\end{matrix} $

In this example, the CBL is a constant CBL, a same day CBL. The CBL isillustrated by the equation below.

$e_{{CBL},i} = \frac{e_{6} + e_{7} + e_{8} + e_{20} + e_{21}}{5}$

Cost function modifier 1010 can be configured to modify a cost functiongenerated by high level optimizer 632. The modified cost function isshown in the equation below. The CBL received from baseline generator1002, e_(CBL,i), is an input to the ELDR term of the cost functionbelow. Further, the participation hours, p_(i), is another binary inputto the ELDR term. As can be seen in the cost function below, theoptimization period is a day, i.e., 24 hours. For this reason, thesummation functions below include indices 1-24. In various embodiments,the optimization period is a day, a month, a year, and/or any otherlength of time.

$J = {{\sum\limits_{i = 1}^{24}{{\hat{r}}_{e_{i}}e_{i}}} - {\sum\limits_{i = 1}^{24}{p_{i}{{\hat{r}}_{{RT}_{i}}( {e_{{CBL},i} - e_{i}} )}}} + \ldots}$

As an example, the CBL illustrated in the above equation can besubstituted directly into the cost function illustrated above. Theresult is the following equation.

$J = {{\sum\limits_{i = 1}^{5}{{\hat{r}}_{e_{i}}e_{i}}} + {( {{\hat{r}}_{e_{6}} - \frac{\sum_{i = 10}^{18}{\hat{r}}_{{RT}_{i}}}{5}} )e_{6}} + {( {{\hat{r}}_{e_{7}} - \frac{\sum_{i = 10}^{18}{\hat{r}}_{{RT}_{i}}}{5}} )e_{7}} + {( {{\hat{r}}_{e_{8}} - \frac{\sum_{i = 10}^{18}{\hat{r}}_{{RT}_{i}}}{5}} )e_{8}} + {{\hat{r}}_{e_{9}}e_{9}} + {\sum\limits_{i = 10}^{18}{( {{\hat{r}}_{e_{i}} + {\hat{r}}_{{RT}_{i}}} )e_{i}}} + {{\hat{r}}_{e_{19}}e_{19}} + {( {{\hat{r}}_{e_{20}} - \frac{\sum_{i = 10}^{18}{\hat{r}}_{{RT}_{i}}}{5}} )e_{20}} + {( {{\hat{r}}_{e_{21}} - \frac{\sum_{i = 10}^{18}{\hat{r}}_{{RT}_{i}}}{5}} )e_{21}} + {\sum\limits_{i = 22}^{24}{{\hat{r}}_{e_{i}}e_{i}}}}$

As can be seen in the equation above, the electric rates, {circumflexover (r)}_(e) _(i) , are adjusted by either a negative rate adjustment,a positive rate adjustment, or are not adjusted. For CBL hours, the rateadjustment may be negative. For participation hours, the rate adjustmentmay be positive. For hours that are neither CBL hours nor participationhours, there may be no rate adjustment. For example, based on theequation above, the rate adjustment may be

$- \frac{\sum_{i = 10}^{18}{\hat{r}}_{{RT}_{i}}}{5}$

for hours 6-8 and 20 and 21 since these hours are CBL hours. The rateadjustment may be {circumflex over (r)}_(RT) _(i) for hours 10-18 sincethese hours are participation hours. Further, for the hours that areneither CBL hours nor participation hours, there may be no rateadjustment.

In this example, since the electric rates are lower during the CBL hoursand higher during the participation hours, it should be expected thatthe optimization will make the decision to lower the electric use duringthe participation hours. As a physical example, if a battery exists inbuilding (e.g., buildings 116), based on the optimization (e.g., theelectric loads) controller 1000 will tend to charge the battery duringthe CBL hours and discharge it during the participation hours. Further,if a co-gen exists in the building, based on the optimization (e.g., theelectric loads) controller 1000 will tend to turn the co-gen on duringthe participation hours and turn the co-gen off during the CBL hours.

Referring now to FIG. 11B, a flow diagram of a process 1101 for using acost function to determine optimal electric loads for participation inan ELDR program is shown, according to an exemplary embodiment.Controller 1000, and the various components of controller 1000, can beconfigured to perform process 1101. In some embodiments, process 1101 isperformed by various components of high level optimizer 632 (e.g., assetsizing module 916, cost function module 902, etc.) as described withreference to FIGS. 9-10. Process 1101 can be performed by frequencyresponse optimization system 100, photovoltaic energy system 300, energystorage system 500, planning system 700, or any other type of energystorage system.

In step 1122, process 1101 is shown to include generating a costfunction defining a cost of operating HVAC equipment as a function ofelectric loads (e.g., decision variables) for the HVAC equipment. Insome embodiments, the cost function is the original cost function J(x).The cost function J(x) may include terms that accounts for energypurchase costs, demand charges, and peak load contribution (PLC)charges. In some embodiments, the cost function J(x) accounts forrevenue from participating in IBDR programs such as frequency regulation(FR).

The HVAC equipment may include individual HVAC devices (e.g., chillers,boilers, fans, pumps, valves, batteries, co-gens, etc.) or collectionsof HVAC devices (e.g., a chiller subplant, a heater subplant, a coolingtower subplant, etc.). In some embodiments, the HVAC equipment includeenergy storage such as thermal energy storage and/or electrical energystorage (e.g., batteries). Although HVAC equipment is used as an examplein process 1101, it should be understood that any type of equipment canbe used. For example, the cost function generated in step 1122 mayaccount for the cost associated with operating any type of equipment.

In step 1124, LMP predictor 1014 can generate a predicted real-time LMPand a predicted day-ahead LMP. In some embodiments, LMP predictor 1014generates the predicted real-time LMP and the day-ahead LMP based on anactual real-time LMP and/or an actual day-ahead LMP received fromincentive program 1012. LMP predictor 1014 can be configured to retrieveand/or receive a real-time LMP from incentive program every fifteenminutes and/or a day ahead LMP once every day. In some embodiments, theprediction is made based on weather data (e.g., daily temperatures,humidities, rain forecasts, etc.) In some embodiments, LMP predictor1014 stores historical LMP data based on LMP data received fromincentive program 1012 and uses the historical LMP data to train apredictive model that LMP predictor 1012 can use to generate a predictedLMP.

In step 1126, participation predictor 1004 can generate participationhours. Participation predictor 1004 can use a CBL, the predictedreal-time LMP, the predicted day-ahead LMP, the predicted electric load,and/or an NBT threshold value. In some embodiments, participationpredictor 1004 determines the participation hours by determining thatthe participation hours are hours where the predicted real-time LMP isgreater than or equal to the NBT threshold value or the predictedday-ahead LMP is greater than or equal to the NBT threshold value.

In some embodiments, participation predictor 1004 further refines theparticipation hours by using a CBL, the predicted electric load, amaximum power limit, and a grid power limit. Using the participationhours as a searching space (e.g., search hours) participation predictor1004 can minimize the equation below to determine a starting time (e.g.,event start ES) and an ending time (e.g., event end EE) that defines theparticipation hours.

$\min\limits_{{ES},{EE}}( {- {\sum\limits_{i = {ES}}^{EE}{{\hat{r}}_{{RT}_{i}}( {e_{{CBL},i} - {\max( {( {{\hat{e}}_{i} - P_{\max}} ),P_{gridLimit}} )}} )}}} )$

In step 1128, based on the participation hours, cost function modifier1010 can generate an ELDR term for the cost function based on theparticipation hours and a CBL. Cost function modifier can replace thevarious terms of the ELDR term with the participation hours, a CBL basedon the participation hours, and the predicted real-time LMP. The terme_(CBL,i) may be replaced with the CBL, the term {circumflex over(r)}_(RT) _(i) may be replaced with the predicted real-time LMP, whilethe term p_(i) may be replaced with the participation hours (e.g., avector indicating participation at the i^(th) hour).

$- {\sum\limits_{i = k}^{k + h - 1}{p_{i}{{\hat{r}}_{{RT}_{i}}( {e_{{CBL},i} - e_{i}} )}}}$

In step 1130, cost function modifier 1010 can modify the cost functionwith the ELDR term generated in step 1110. In some embodiments,modifying the cost function involves adding the ELDR term to the costfunction. An example of a modified cost function including the ELDR termis the equation below.

$J = {{\sum\limits_{i = k}^{k + h - 1}{{\hat{r}}_{e_{i}}e_{i}}} - {\sum\limits_{i = k}^{k + h - 1}{p_{i}{{\hat{r}}_{{RT}_{i}}( {e_{{CBL},i} - e_{i}} )}}}}$

In step 1132, high level optimizer 632 optimizes the modified costfunction of step 1130. High level optimizer 632 can use one or more of aplurality of different types of optimizations known in the art. In someembodiments, the optimization is performed by linear programming and/ormixed integer linear programming. In some embodiments, high leveloptimizer 632 uses one or more constraints when performing theoptimization. The result of the optimization may be one or more electricloads, e_(i), wherein e_(i) is the electric load at a plurality ofhours, i.

In step 1134, bid controller 1006 can generate a bid to send toincentive program 1012. The bid may be generated based on theparticipation hours and/or the electric loads. In some embodiments, thebid is further based on the predicted real-time LMP and the predictedday-ahead LMP. In some embodiments, the bid includes a curtailmentamount which bid controller 1006 can determine. The curtailment amountmay be the difference between a CBL and the electric load at each of aplurality of hours. The bid may further include the participation hours.Finally, the bid may include a compensation amount and/or rate for eachhour. The compensation rate may be the predicted real-time LMP and/orthe predicted same day LMP and/or a compensation amount determined basedon the predicted real-time LMP and/or the predicted same day LMP. Insome embodiments, bid controller 1006 can remove participation hoursfrom the bid where the participation hours have a correspondingcurtailment less than or equal to zero.

In step 1136, participator 1018 can receive awarded hours. The awardedhours may be hours bid controller 1006 sends to incentive program 1012.Participator 1018, high level optimizer and/or otherwise controller 1000can control the HVAC equipment based on the awarded hours and theelectric loads that correspond to the awarded hours. In someembodiments, participator 1018 uses an operating constraint to operatethe HVAC equipment based on the electric loads for the awarded hours.

Referring now to FIG. 12 a graph 1200 illustrating participation in theELDR program is shown, according to an exemplary embodiment. Graph 1200is shown to include electric load in kilowatts on the vertical y-axisand time in hours on the horizontal x-axis. The solid line, electricload 1202, represents a typical electric load of a campus (e.g., campus102), building, or facility. The dotted line indicates the electricload, ELDR load 1204, of the campus when participating in the ELDRprogram. Electric load 1202 may represent a typical electric load ofcampus 102. As can be seen, ELDR load 1204 is a reduction in electricload as compared to the typical electric load, electric load 1202. TheELDR load 1204, indicates a reduction in electric load for the campusduring the participation time 1206

Referring now to FIG. 13, a graph 1300 illustrating a same day CBL isshown, according to an exemplary embodiment. Graph 1300 is shown toinclude CBL 1302 and electric load 1304. CBL 1302 is shown to be aconstant value. Electric load 1304 may represent the electric load of acampus (e.g., campus 102) over time. Start time 1306 and end time 1308are shown as vertical lines marking the beginning and the end of aplurality of participation in the ELDR program. In graph 1300, starttime 1306 is hour 11 while end time 1308 is hour 20. CBL Hours 1310represent the hours that baseline generator 1002 can be configured touse when calculating a same day CBL. CBL hours 1310 are the three hoursone hour before the participation time begins. Similarly, CBL hours 1312can be used by baseline generator 1002 to generate a same day CBL. Thesehours represent the two hours that occur one hour after the end of theparticipation period. The curtailment amount in indicted in FIG. 13. Thedifference between electric load 1304 and same day CBL 1302 is thecurtailment amount.

Referring now to FIG. 14, a graph 1400 illustrating an SAA CBL 1402 isshown, according to an exemplary embodiment. SAA CBL 1402 may be anexample of the CBL that baseline generator 1002 provides participationpredictor 1004 with. In graph 1400, SAA CBL 1402 is shown in addition toelectric load 1404. As can be seen, electric load 1404 is reducedbetween start time 1410 and end time 1412. The length of time betweenstart time 1410 and end time 1412 may represent the time that controller1000 participates in the ELDR program, CBL hours 1408. SAA CBL 1402 maybe determined by baseline generator 1002. The equation below mayrepresent SAA CBL 1402.

e _(CBL)=[e _(CBL,1) . . . e _(CBL,24)]

Start time 1410 and end time 1412 may represent the time that acontroller (e.g., controller 1000) participates in an ELDR program.Graph 1400 is shown to include SAA hours 1406. SAA hours 1406 may be theduration of three hours that occur one hour before start time 1410. Theelectric load 1404 during SAA hours 1406 may be used to calculatee_(SAA) as described with reference to FIG. 10, specifically baselinegenerator 1002. Baseline generator 1002 may use the equation below togenerate e_(SAA). Start time 1410 may correspond to the term ES whileend time 1412 may correspond to the term EE. The terms e_(0k) and ē_(k)may be derived from electric load 1404.

$e_{SAA} = {\sum\limits_{k = {{ES} - 4}}^{{EE} - 2}\frac{e_{0\; k} - {\overset{\_}{e}}_{k}}{3}}$

CBL Hours 1408 may be the hours that are used by baseline generator 1002to generate the average electric load for each day. CBL Hours 1408 maybe represented by the term k E participation in the equation below.However, it should be understood that the electric load at an hour ofCBL Hours 1408, e_(ik), is not electric load 1404. Rather, it is theelectric load for the i^(th) day, which is a day prior to the day withparticipation in the ELDR program illustrated in graph 1400.

${{\overset{\_}{d}}_{i} = {{\sum\limits_{k \in {participation}}{\frac{e_{ik}}{n}\mspace{14mu}{\forall i}}} = 1}},\ldots\;,5$

Referring now to FIGS. 15-16, an interface 1500 for controller 1000 isshown for outputting information for participation in an ELDR program toa user and receiving user input is shown, according to an exemplaryembodiment. Interface 1500 may be an interface generated by GUI engine614. In various embodiments, interface 1500 is an interface displayed ona terminal connected to controller 1000 that GUI engine 614 isconfigured to operate. In various embodiments, interface 1500 is aninterface of an application on a mobile device or computer (e.g., userdevice 1013). FIG. 15 is an illustration of interface 1500 duringparticipation in an ELDR program on a particular day. FIG. 16 is anillustration of interface 1500 of a previous day on which controller1000 participated in the ELDR program.

In FIGS. 15-16, interface 1500 illustrates electric loads at varioushours of a particular day. The hours 1502, located along the horizontalaxis of the graph shown in interface 1500 includes a plurality of boxesfor each hour of a day. The boxes allow a user to select one or moretimes that the user would like to controller 1000 to participate in theELDR program. The user may only be able to select a time whilecontroller 1000 can be configured to determine the curtailment for theselected time. In various embodiments, the user can also view the hoursthat controller 1000 has automatically determined it will participate inthe ELDR program. In this regard, a user can “deselect” a box thatindicates participation to override the participation on the ELDRprogram at a particular hour or hours. A user can view a plurality ofdifferent days in the future and/or in the past. A user may interactwith program availability icon 1504 to navigate to a plurality ofdifferent days, weeks, months, or years to view the ELDR programparticipation information for a particular day, week, month, and/oryear.

In interface 1500, the vertical line, start time 1520, indicates thestart time of participation in the ELDR program while the vertical line,end time 1522 indicates the ending time of participation in the ELDRprogram. Current time line 1524 indicates the current time of day. Thecurtailment area 1510 indicates the difference between an actualelectric load 1506 and baseline 1508. In some embodiments, theparticipation hours are not contiguous, in this embodiment, there may bemultiple curtailment areas. Predicted electric load 1512 graphicallyillustrates a predicted electric load. This may be a plurality of powersetpoints that high level optimizer 632 determines by optimizing a costfunction. Interface 1500 is further shown to include day-ahead LMP 1516.Day-ahead LMP 1516 may be the actual day-ahead LMP that controller 1000receives from incentive program 1012. Real-time LMP 1514 shown ininterface 1500 is a real-time LMP received from incentive program 1012.Predicted real-time LMP 1518 may be a real-time LMP predicted by LMPpredictor 1014.

In some embodiments, interface 1500 indicates various informationpertaining to the participation in the ELDR program. In someembodiments, a current operating day date is displayed on interface1500, a NBT threshold value for the operating day is displayed, and apredicted curtailment amount is displayed. In some embodiments,interface 1500 includes an indicator which indicates which hours arelocked and cannot be modified by a user and which hours a user canmodify (e.g., hours where the current time is at least three hoursbefore the top of the hour). If a user override is available viainterface 1500, the hours that the user can override may be a particularcolor and/or have a particular shading. In some embodiments, when a userhovers over curtailment area 1510, a popup may appear indicating thecurtailment amount and a current revenue made (e.g., for theparticipation period and/or for a particular hour).

When a particular day is over and/or the ELDR participation is over,interface 1500 may display metrics regarding the performance in the ELDRparticipation. In some embodiments, the metrics include averagecurtailment amount and/or ELDR revenue (see FIG. 16). In variousembodiments, interface 1500, specifically the current operating day, isa default home screen. In various embodiments, a user can select data todisplay on interface 1500 and can zoom in on various locations ofinterface 1500.

In some embodiments, interface 1500 includes multiple settings that areset in the code of interface 1500 by a programmer or are set byinterface 1500 based on the type of baseline that controller 1000generates. The settings may include a “Calculation” setting. Thecalculation setting may be a setting to use a median or an average tocalculate the CBL. The average or median may be used to calculate theCBL after the usage days have been identified and any low usage daysexcluded. The setting “CBL Basis Window” may be a display that indicatesthe typical electric load. The CBL basis window may be the electric loadof five days, the five days is used to calculate the CBL. The five daysmay be all five days used to calculate the CBL or may include any day(e.g., low usage day, participation day, etc.) that would normally beexcluded from the CBL calculation. The “CBL Basis Window Limit” mayindicate the number of days that will be the pool of days that baselinegenerator 1002 selects from when determining the CBL. In someembodiments, the number of days prior to the participation day is 45calendar days. This may be displayed to the user with the explanationthat the 45 days ensure recent information is used when predictingfuture energy consumption e.g., generating a CBL.

A “Start Selection From Days Prior To Event” display may indicate to theuser that baseline generator 1002 selects the most recent days with asimilar day type (e.g., weekend, holiday, weekday) to the participationday. A display may indicate “1” or “2.” A “1” may indicate that baselinegenerator 1002 would select the most recent day for calculating the CBLwhile “2” may indicate that baseline generator 1002 will skip the mostrecent day when selecting days to use in calculation the CBL.

An “Exclude Previous Curtailment Days” setting can be “Yes” or “No.”When “Exclude Previous Curtailment Days” is “Yes,” baseline generator1002 may exclude any previous day which included at least one hour ofparticipation in the ELDR program (e.g., pending or confirmed economicsettlements for the days) from use in calculating the CBL. When it is“No,” baseline generator 1002 may use previous days which include atleast one hour of participation in the ELDR program when determining theCBL.

A setting “Exclude Long/Short DST Days” may be “Yes” or “No.” If thesetting is set to “Yes,” baseline generator 1002 may exclude any DSTdays from being used to determine the CBL. If the setting is set to“No,” baseline generator 1002 may be configured to use DST days whendetermining the CBL. A display “Exclude Average Event Period Usage LessThan Threshold” may indicate that if the Average Daily Event PeriodUsage for a CBL day selected is less than the threshold indicated, thenthat day will be excluded from a CBL basis window.

A setting “Exclude Number of Low Usage Days” may be a number of the daysused to determine the CBL by baseline generator 1002 will be excludedi.e., the number (e.g., 1, 2, 3, or 4) of the lowest days that are to beexcluded. A setting “Use Previous Curtailment If CBL Basis WindowIncomplete” may be set to “Yes” to use previous days that includeparticipation in the ELDR program to determine the CBL if baselinegenerator 1002 cannot find enough non-participation days within the 45day period to generate the CBL. If “Use Previous Curtailment If CBLBasis Window Incomplete” is “Yes” the setting “Exclude PreviousCurtailment Days” may also need to be set to “Yes.”

A setting “Use Highest or Recent Previous Curtailment Day” may be asetting that can be set if the setting “Use Previous Curtailment Day ifCBL Incomplete” is “Yes.” A setting of “Highest” for the “Use Highest OrRecent Previous Curtailment Day” may cause baseline generator 1002 torank previous curtailment days based on event period usage within theCBL Basis Day Limit and add them to the CBL Basis Days in descendingorder until the CBL Basis Days contains the minimum number of daysrequired to calculate CBL. The setting “Recent” may cause baselinegenerator 1002 to start adding days to the CBL Basis Days starting withthe Most Recent Curtailment Day that was excluded until the CBL BasisDays contains the minimum number of days required to calculate CBL.

A display “Adjustments” may indicate that Symmetric Additive Adjustmentis a CBL average usage for an event day divided by Adjustment BasisHours for the same hours. The display may further indicate that aweather sensitivity adjustment compares weather over CBL days to weatheron event days and then calculates the adjustment based on weathersensitivity.

A setting “Allow Negative Adjustments” may be set to “Yes” in which caseadjustments may be either positive or negative. If this setting is not“Yes,” adjustments may always be greater than zero. A display“Adjustments Start (HE0-x)” may indicate a starting point for hours tobe used in calculating the Adjustments. If the event starts with HE13and Adjustment Start is 4, then HE9 may be the first hour used tocalculate Adjustments. A display “Adjustment Basis Hours” may indicatethat the total number of hours used to determine the adjustment from“Adjustment Start.” If the event is on HE13, “Adjustment Start” is 4,and “Adjustment Basis Hours” is 3, then the adjustment may be based onthe load from HE9-HE11.

Automated and Dynamic Economic Load Demand Response (ELDR) ProgramParticipation with ELDR User Interfaces

Referring now to FIG. 17, a block diagram of system 1700 including anELDR module 1706, a Curtailment Service Provider (CSP) 1704, and aregional transmission organization and/or independent system operator(RTO/ISO) 1702 are shown, according to an exemplary embodiment. ELDRmodule 1706 can be a module of incentive program module 912 and/or highlevel optimizer 632. ELDR module 1706 can perform some and/or all of theELDR related functions as described with reference to FIGS. 10-16 toparticipate in an ELDR program.

CSP 1704 may be one or more computing systems, servers, and/or devicesconfigured to facilitate the ELDR program. CSP 1704 can be a systemconfigured to facilitate participation in the ELDR program. In someembodiments, CSP 1704 is “CPower.” RTO/ISO 1702 can include one or morecomputing systems, servers, and/or devices. RTO/ISO 1702 can beconfigured to perform the ELDR program by generating various ELDRparameters and providing the ELDR parameters to ELDR module 1706 via CSP1704. Furthermore, ELDR module 1706 can provide various load reductionbids to RTO/ISO 1702 via CSP 1704. RTO/ISO 1702 can be, as an example,the Pennsylvania, New Jersey, and Maryland (PJM) RTO.

System 1700 provides a high-level description of an automated anddynamic participation process that ELDR module 1706 can be configured toperform for ELDR program participation. In some cases, participation inthe ELDR program may be manual and involve human interaction. Forexample, a user associated with a power plant of a building and/orcampus could make the participation decisions (e.g., participation hoursand a constant kW load reduction amount) for an ELDR program for afollowing day. The user could make a selection manually through a userinterface of CSP 1704. Based on the participation decision, the user candetermine the schedule of the plant equipment (e.g., Gas Turbines,chillers, boilers, etc.) in order to meet his ELDR commitment for thefollowing day.

The schedule of the equipment and the kW participation amount do notchange dynamically with the dynamic changes and/or updates of marketprices, plant status the day of participation, awarded bids, etc. whenmanual selection of participation is used. In this regard, ELDR module1706 can remove direct user interaction for participating in the ELDRprogram in order to automate the participation in the ELDR program,making the ELDR participation dynamic and adaptive to changes in prices,schedules, weather, etc. However, ELDR module 1706 can provide the userwith a user interface and the ability to override various participationdecisions of ELDR module 1706. This allows a user to have control overparticipation in the ELDR program but participate in the ELDR program inan automated and dynamic manner such that the benefit of participationin the ELDR program is maximized.

The automated ELDR program participation provided by ELDR module 1706can perform various functions to dynamically participate in the ELDRprogram. ELDR module 1706 can be configured to perform prediction ofELDR parameters. For example, ELDR module 1706 can be configured toperform predictions of real-time LMP and day-ahead LMP prices based oncurrent prices (e.g., current values for real-time LMP and/or day-aheadLMP), weather forecast data, time of day, and/or day of week. The ELDRcan be configured to dynamically respond to changes in market prices.For example, the participation hours and/or participation amounts may bydynamically adjusted throughout a particular day and/or preceding theparticular day to account for changes in market prices so that ELDRmodule 1706 maximizes the potential revenue from participating in theELDR program.

Furthermore, ELDR module 1706 can be configured to perform optimalallocation of equipment in order to minimize cost while maximizing thebenefit of the ELDR program. ELDR module 1706 can be configured toperform automatic determination of the kW participation amount,automatically submit bids to CSP 1704, automatically read the status(e.g., awarded or not awarded) of submitted participation hours, and/ordynamically update equipment allocation based on the awarded status ofparticipation hours.

ELDR module 1706 is shown to include various “collectors” configured tocollect ELDR parameters from CSP 1704 and/or receive awarded hours fromCSP 1704. The collectors may be one single module and/or multiplemodules. In FIG. 17, multiple collector modules are shown. ELDR module1706 is shown to include a real-time LMP collector 1708, a day-ahead LMPcollector 1710, an awarded bids collector 1712, and a NBT pricecollector 1714. Furthermore, ELDR module 1706 is shown to include a bidsubmitter 1716 for submitting bids to CSP 1704. CSP 1704 may include aspecific application programing interface (API) for communicating ELDRdata with ELDR module 1706. In this regard, the collectors of ELDRmodule 1706 can be configured to integrate with the API of CSP 1704 tosend and/or receive data from the CSP 1704.

All settings of ELDR module 706 e.g., ELDR program settings, jobscheduling (e.g., collection periods and/or frequencies of collectors1708-1714), and retry settings can be configurable at deployment time ofELDR module 1706 and/or after the deployment time. Collection jobs canbe individually disabled if necessary, for example, during commissioningwhen ELDR module 1706 is not set up to submit bids. A technician coulddisable the scheduled collection of day-ahead LMP by day-ahead LMPcollector 1710 but allow real-time LMP collector 1708 to continue toperform collection of the real-time LMP in order to perform troubleshooting. Setting changes to ELDR module 1706 may require a servicerestart.

Collectors 1708-1714 and bid submitter 1716 can each be configured (orcan collectively be configured) to generate a log that detailsinteractions with CSP 1704. The log may indicate errors and/or errorcodes returned by CSP 1704 responsive to a message (e.g., a collectionmessage). For example, if the awarded bids collector 1712 attempts toretrieve an indication of an awarded bid but instead receives an error,awarded bids collector 1712 can be configured to generate an error logand/or update an existing error log with an indication of the errorand/or an error code. Collectors 1708-1714 and bid submitter 1716 mayinclude various general settings used for collecting data from CSP 1704.The settings may include an endpoint, a username, and/or a password forconnecting with CSP 1704. The settings can include an identification ofRTO/ISO 1702, “IsoName.” An example of an “IsoName” may be “PJM.” Thesettings can further include a “ZoneName,” a “BidGroupName,” a“ProductTypeName,” and an “IsoTimeZoneId.”

Real-time LMP collector 1708 can be configured to collect a sub-hourlyreal-time LMP from CSP 1704. Real-time LMP collector 1708 can beconfigured to send a read command to CSP 1704 for a real-time LMP valueand receive the value for the real-time LMP from CSP 1704 in response tosending the read command. In some embodiments, real-time LMP collector1708 can be configured to periodically read the real-time LMP and storethe real-time LMP in a database. In some embodiments, real-time LMPcollector 1708 can collect the real-time LMP on an sub-hourly period(e.g., every minute, every ten minutes, every half hour, etc.) Real-timeLMP collector 1708 can include a database configured to store collectedreal-time LMP values.

In some embodiments, real-time LMP collector 1708 can share a databasewith the other collectors, e.g., an ELDR parameter database 1709. TheELDR parameter database 1709 can act as a data repository for thevarious collected ELDR parameters, generated ELDR parameters (e.g.,predicted ELDR parameters), and/or any other ELDR information.

CSP 1704 can include an endpoint for real-time LMP, e.g.,“lmp/zoneinterval endpoint.” Real-time LMP collector 1708 can use thisendpoint to periodically collect (e.g., five minute) real-time LMPvalues. Real-time LMP collector 1708 can be configured to determine asliding window average (e.g., a moving average window, an exponentiallyweighted moving average filter, etc.) which we use to calculate anaverage. In some embodiments, there may be gaps in the real-time LMPprices since RTO/ISO 1702 may withhold the prices to prevent marketmanipulation. The sliding window average allows ELDR module 1706 tohandle these gaps in real-time LMP prices as well as smooth out suddenspikes in real-time LMP prices.

Real-time LMP collector 1708 may include specific configurable settingsfor collecting real-time LMP prices from CSP 1704. The settings mayinclude a “Job Scheduled Period” which defines the rate at whichreal-time LMP collector 1708 collects real-time LMP prices from the CSP1704. The settings may further include an “Offset” parameter providingan offset to the collected real-time LMP prices, and/or an enabled flagwhich causes real-time LMP collector 1708 to collect real-time LMPprices from CSP 1704 when enabled. The settings may include a“RealTimeLmpWindowSize” which may define the size of the moving averagewindow (e.g., the number of samples used to determine the averagedreal-time LMP price). Real-time LMP collector 1708 can include a“RealTimeLmpOutgoingSampleInterval” which may be a setting defining therate at which real-time LMP collector 1708 determines an outgoingreal-time LMP price for providing to predictor 1718 and/or storing inELDR parameter database 1709.

Day-ahead LMP collector 1710 can be configured to collect an hourlyday-ahead LMP from CSP 1704. Day-ahead LMP collector 1710 can beconfigured to send a read command to CSP 1704 for a day-ahead LMP andreceive a value for the day-ahead LMP from CSP 1704. In someembodiments, day-ahead LMP collector 1710 can be configured toperiodically read the hourly day-ahead LMP and store the day-ahead LMPin a database. In some embodiments, day-ahead LMP collector 1710 cancollect the day-ahead LMP on an hourly period. Day-ahead LMP collector1710 can include a database configured to store the collected real-timeLMP values. In some embodiments, day-ahead LMP collector 1710 can sharea database with the other collectors, e.g., ELDR parameter database1709.

The day-ahead LMP prices may be made available by CSP 1704 for afollowing day after a particular time on a current day (e.g., 12:30P.M.) Sometimes, CSP 1704 may post the day-ahead LMP prices late or maylater revise the posted day-ahead LMP prices. To compensate in thisuncertainty in posting time and/or updating, day-ahead LMP collector1710 can be configured to periodically read the day-ahead LMP pricesthroughout the day. In some embodiments, CSP 1704 make the day-ahead LMPprices available at a specific endpoint, e.g., a “lmp/zone endpoint”where day-ahead LMP collector 1710 can be configured to retrieve theday-ahead LMP values from.

Day-ahead LMP collector 1710 can include multiple configurable settings.The settings may include a “Job Scheduled Period” which defines howfrequently day-ahead LMP collector 1710 collects the day-ahead LMPprices. Day-ahead LMP collector 1710 can further include an offsetparameter which can provide an offset to the collected day-ahead LMPprices. Day-ahead LMP collector 1710 can include an enabled flag whichcauses day-ahead LMP collector 1710 to collect the day-ahead LMP valuesfrom CSP 1704 whenever enabled. Day-ahead LMP collector 1710 mayperiodically collect the day-ahead LMP price after a particular time ona given day. This time may be configurable and may be a setting“DayAheadPriceAvailabilityTimeOfDay.” After the particular set timepasses, day-ahead LMP collector 1710 can be configured to periodicallycollect day-ahead LMP values for CSP 1704.

Awarded bids collector 1712 can be configured to collect awarded bidsfrom the CSP 1704. The awarded bids may be indications that particularparticipation hours submitted in a bid by bid submitter 1716 have beenapproved. Awarded bids collector 1712 can be configured to send a readcommand to CSP 1704 for awarded bids and receive an indication of theawarded bids from the CSP 1704 responsive to submitting the readcommand. In some embodiments, the awarded bids collector 1712 can beconfigured to periodically read the awarded bids and store the awardedbids in a database. In some embodiments, awarded bids collector 1712 cancollect the awarded bids on an hourly and/or sub-hourly period (e.g.,every minute, every ten minutes, every half hour, every hour, every twohours, etc.). Awarded bids collector 1712 can include a databaseconfigured to store the collected awarded bids. In some embodiments,awarded bids collector 1712 can share a database with the othercollectors, e.g., ELDR parameter database 1709.

In response to RTO/ISO 1702 awarding the first bid of a particular day,CSP 1704 may indicate that all bids for all hours of the particular dayare awarded even though RTO/ISO 1702 may later decline bids. Awardedbids collector 1712 can include multiple settings for collected awardedbids, e.g., the participation hours that have been awarded, from CSP1704. The settings may include a job scheduled period which causesawarded bids collector 1712 to collect bids at a particular rate.Awarded bids collector 1712 can also include an offset setting.Furthermore, awarded bids collector 1712 can include an “Enabled Flag”which causes awarded bids collector 1712 to collect awarded bids fromCSP 1704 at a particular defined rate.

Awarded bids collector 1712 may include a “AwardedBidsHorizon” settingwhich defines a time span preceding a particular participation hour.Once a current time is within the timespan, the particular participationhour will be assumed to be awarded if the current status of theparticular participation hour is awarded. Similarly, awarded bidscollector 1712 can include a “NotAwardedBidsHorizon” which may defineanother timespan preceding a participation hour. If the current time iswithin the timespan and the status of the particular participation houris not awarded, awarded bids collector 1712 can assume that the currentparticipation hour is not awarded.

NBT price collector 1714 can be configured to collect NBT thresholdvalues from CSP 1704. Awarded bids collector 1712 can be configured tosend a read command to CSP 1704 for an NBT threshold value and receivethe NBT threshold value from CSP 1704 responsive to sending the readcommand to CSP 1704. NBT price collector 1714 can be configured toperiodically, e.g., every day, collect the NBT threshold value and storethe collected NBT threshold value. NBT price collector 1714 can storethe collected NBT threshold value by itself or otherwise store the NBTthreshold value in ELDR parameter database 1709.

RTO/ISO 1702 may provide CSP 1704 with an NBT threshold for a followingmonth on a particular day of a current month (e.g., the 15^(th) of thecurrent month). CSP 1704 may make the NBT threshold available at least apredefined amount of time before the next month, e.g., at least 10 daysbefore the end of the month. CSP 1704 may include a particular endpointwhere CSP 1704 can make the NBT threshold available. For example, theendpoint may be an “nbt/price” endpoint. In some cases, CSP 1704 may notprovide an indication as to whether the NBT threshold value is availableor not. Furthermore, in some cases, the NBT threshold can even beupdated during a particular month for which the NBT threshold valueapplies. For this reason, NBT price collector 1714 can be configured tocollect the NBT threshold value on a periodic basis e.g., daily.

NBT price collector 1714 can include one or multiple settings forcollecting the NBT price value from CSP 1704. The NBT setting caninclude a job scheduled period which defines the rate at which NBT pricecollector 1714 collects the NBT threshold from CSP 1704. Furthermore,NBT price collector 1714 may include an offset which may provide anoffset to the value of the NBT threshold. Furthermore, NBT pricecollector 1714 can include an enabled flag which enables or disables theoperation of NBT price collector 1714. In some embodiments, NBT pricecollector 1714 can include a retry sleep duration time and a retrycount. The retry time may be a particular time which NBT price collector1714 waits before retrying to collect the NBT threshold value from CSP1704 in response to NBT price collector 1714 failing to collect the NBTthreshold value. NBT price collector 1714 can be configured to count thenumber of retry attempts that NBT price collector 1714 attempts. If thenumber of attempted retries is greater than a predefined amount, NBTprice collector 1714 may stop retrying to retrieve the NBT thresholdvalue and may resume collecting the NBT price collector based on the jobscheduled period.

Bid submitter 1716 can be configured to submit bids received fromoptimizer 1722 to CSP 1704. In some embodiments, bid submitter 1716 cansubmit participation hours and estimated participation amounts for eachparticipation hour. In some embodiments, bid submitter 1716 submits abid in response to optimizer 1722 determining an estimated participationamount and/or participation hours. In some embodiments, optimizer 1722may determine the estimated participation amount and/or participationhours on a periodic basis, e.g., every fifteen minutes. In this regard,bid submitter 1716 can be configured to submit a bid to CSP 1704 everyfifteen minutes.

Bid submitter 1716 can sign up for a notification regarding whenoptimizer 1722 creates a dispatch for ELDR module 1706 (e.g., determinean estimated participation amount for participation hours determined byparticipation kernel 1720). Bid submitter 1716 can be configured togenerate a bid to provide to CSP 1704 based on the estimatedparticipation amount and the participation hours received from optimizer1722. In some embodiments, the bid that bid submitter 1716 provides toCSP 1704 includes the estimated participation amount and/or theparticipation hours determined by optimizer 1722 and/or participationkernel 1720. The dispatch results can include the participation hoursand amounts that we should include in our bid.

Bid submitter 1716 can include multiple configurable settings forproviding a bid to CSP 1704. The settings may include a job enabled flagwhich indicates whether bid submitter 1716 should operate. The settingsmay further include a “MaximumBidQuantityMw” which may be a cap for theestimated participation amount so that the participation amount does notexceed a reasonable level. The settings may include a“MinimumBidQuantityMw” which acts as a bottom level for the estimatedparticipation amount. Any participation hour associated with anestimated participation amount below the minimum level may be considereda non-participation hour and left out of the bid to CSP 1704. Bidsubmitter 1716 can further include a “BidQuantityFractionalDigits”setting which defines the precision for the estimated participationamounts that CSP 1704 may be willing to accept. Bid submitter 1716 mayalso include a lockout period setting. This lockout period setting mayalso be implemented by user interface manager 1724. This setting maydefine a time span preceding a particular participation hour withinwhich the user is not allowed to override or otherwise change theparticipation hour, causing a change to the bids placed to CSP 1704.Prior to the timespan, a user can be allowed to make changes to theparticipation hours via user interface manager 1724 and provideparticipation hour overrides to participation kernel 1720. This maycause bid submitter 1716 to made adjustments to current bids bysubmitting a second bid. However, within the time span, both userinterface manager 1724 and/or bid submitter 1716 may stop makingadjustments or placing new bids for a particular participation hour.

Since the collection of ELDR parameters and/or awarded bids may beperformed over a network (e.g., the communication between ELDR module1706 and CSP 1704 may be performed over a network such as the Internet),ELDR module 1706 can be configured to detect and/or recover fromtransient network errors and/or longer network and service outages.Collectors 1708-1714 can implement retry mechanisms (e.g., sending amessage a second time if the first message is not delivered) to recoverfrom transient network errors. In some embodiments, ELDR module 1706 canbe configured to perform a long retry mechanism for collectors that runinfrequently, e.g., NBT price collector 1714. The periodic scheduling ofcollection jobs and periodic nature of the optimization runs whichtrigger bid submission, provide another level of retries for handlinglonger outages. The collectors that read time series data (e.g., prices,NBT threshold, awarded bids) (e.g., collectors 1708-1714) can beconfigured to backfill with past data to fill gaps in data collectioncaused by network outages. Furthermore, any call to a database ofcollectors 1708-1714 and/or ELDR parameter database 1709 can use a retrymechanism to protect from transient errors.

In some embodiments, ELDR module 1706 is implemented on a server. Eachof collectors 1708-1714 and/or bid submitter 1716 may be a MICROSOFTWINDOWS® service that can automatically start whenever the server isrestarted and can be configured to automatically restart if the servicecrashes. In some embodiments, upon a startup of ELDR module 1706, eachof collectors 1708-1714 can be configured to backfill time series datathat may be missing from the time period where collectors 1708-1714 werenot collecting data.

Predictor 1718 can be configured to receive real-time LMP values fromreal-time LMP collector 1708, day-ahead LMP values from day-ahead LMPcollector 1710, and/or historic electric load data. Based on thereceived data, predictor 1718 can be configured to predict the receiveddata into the future. Predictor 1718 is shown to generate a predictedday-ahead LMP, a predicted real-time LMP, and a predicted campus load.Predictor 1718 may be the same as and/or similar to load/rate predictor622 as described with reference to FIG. 10 and elsewhere herein.

Participation kernel 1720 can be configured to generate participationhours to be used by optimizer 1722. Participation kernel 1720 can beconfigured to generate the participation hours based on the predictedday-ahead LMP, the predicted real-time LMP, a predicted campus load, ameasured imported electricity, awarded participation hours, and/or a NBTthreshold value. Participation kernel 1720 can be and/or include thefunctionality of participation predictor 1004 and/or selector 1008.Participation kernel 1720 can include some and/or all of thefunctionality for generating the participation hours as described withreference to FIGS. 10-16.

Participation kernel 1720 can be configured to determine theparticipation hours and/or estimated participation amounts for hours ofone day or multiple days into the future. In this regard, theparticipation decisions that are shown in the user interfaces generatedby user interface manager 1724 can provide a user with insight into thecurrent day or into multiple days into the future.

In some embodiments, participation kernel 1720 can be configured todetermine the participation hours based on how likely hours of aparticular day will be awarded by the CSP 1704. For example, variousmodeling and/or classification techniques (e.g., neural networks,support vector machines, decision trees, etc.) can be used byparticipation kernel 1720 to determine the participation hours. Forexample, participation kernel 1720 can be configured to set a particularhour at as an hour to participate in the ELDR program based on aclassification of whether or not the particular hour will be awardedbased on historic hour data for real-time LMP, day-ahead LMP, weatherdata, past bid awards and/or rejections. If participation kernel 1720determines, based on the classification, that it is unlikely that aparticular hour is awarded, the participation kernel 1720 may notdetermine to participate in that hour.

Optimizer 1722 can be configured to generate an estimated participationamount for each of the participation hours generated by participationkernel 1720. The estimated participation amount may be a curtailmentamount for reducing an electric load by for a particular participationhour. Optimizer 1722 can include some and/or all of the functionality ofhigh level optimizer 632 and/or cost function modifier 1010. Optimizer1722 can be configured to generate the objective function describedherein with an ELDR term as generated by cost function modifier 1010.Optimizer 1722 can be configured to optimize the generated objectivefunction to determine the estimated participation amounts. Furthermore,the optimizer 1722 can, by optimizing the objective function, determineoperating load amounts for building equipment and cause the buildingequipment to operate based on the operating load amounts.

User interface manager 1724 can be configured to generate a userinterface to present a user with ELDR information (e.g., actual and/orpredicted ELDR parameters, load usage, CBL values, etc.) and receiveELDR hour overrides from a user. User interface manager 1724 can beconfigured to generate the user interfaces of FIGS. 15-16 and/or FIGS.23-31. User interface manager 1724 can receive overridden participationhours from the user interface. The overridden participation hours may behours that participation kernel 1720 has determined but a user does notwant to participate in. Furthermore, the overridden participation hoursmay be hours of a particular day that have not been determined to beparticipation hours but the user would like ELDR module 1706 toparticipate in. User interface manager 1724 can provide the overriddenparticipation hours to participation kernel 1720 so that the useroverride decisions of the user are implemented by participation kernel1720 as desired by the user.

Still referring to FIG. 17, participation kernel 1720 can be configuredto determine whether to participate in the ELDR program for a particularday in response to participation hours for the particular day not beingawarded. ELDR module 1706 can be configured to maximize the revenue fromparticipating in the ELDR program while minimizing the cost of operatingequipment and purchasing resources. In the case of ELDR, the revenue maybe a function of the CBL, which can be either a function of the firstand last hour of participation, or the first hour of participation only.The CBL may be a “Same Day” CBL, a Same Day Three Before and Two Afterbaseline is described with reference to FIG. 10 and elsewhere herein.For a same day CBL, both the first and last hour of participation of aparticular day can determine the baseline hours used to generate thesame day CBL.

To maximize revenue, ELDR module 1706 can be configured, via optimizer1722, to increase electrical import during baseline hours, whiledecreasing the electrical import during participation hours. This keepsthe CBL at an optimally high value such that a difference of the sameday CBL and the electric load consumption during participation hours ismaximized. ELDR module 1706 may have a dynamic response to the awardedstatus of participation hours on a given day. When participating in theReal-Time ELDR Market, a participation hour may or may not get awardedfor curtailment by RTO/ISO 1702. The awarded status of a participationhour may be known by ELDR module 1706 an hour before the top of thathour.

When the first hour of participation does not get dispatched, ELDRmodule 1706, via participation kernel 1720 and/or optimizer 1722, canupdate its allocation decision in order to maintain a high CBL. Thisbehavior may be advantageous since it maintains a high CBL. However,ELDR module 1706 may not be awarded for multiple “first hours” for whichparticipation was bid on a particular day, i.e., it may be late in theday before a bid participation hour is awarded. This can be problematicsince the CBL is being held high for a long period of timeunnecessarily. The hours where ELDR module 1706 may be holding theelectric load high are not turning out to actually be baseline hours.

This performance is shown in FIGS. 21 and 22. For example, theoptimization of the cost function may push the start of the gas turbinesto later in the day in order to maintain the high CBL, but at the end ofthe day the cost of electrical import has surpassed the potentialrevenue from ELDR since optimizer 1722 has kept the energy usage high.This is because ELDR module 1706 makes its decision based on the currentstatus of the plant and what is predicted over the horizon. Therefore,participation kernel 1720 can be configured to determine whether toabandon participation in the ELDR program if ELDR module 1706 does notreceive a first awarded participation hour for an extended period oftime on a particular day.

When the first hour of participation does not get dispatched, it affectsthe value of the CBL and consequently the revenue from ELDR for the dayby ELDR module 1706. In order to overcome the cost of not gettingdispatched, participation kernel 1720 can be configured to determine abenefit by taking into account the revenue for the day and the cost ofresources in order to generate this revenue. Participation kernel 1720can be configured to determine whether the benefit is less than apredefined threshold. In response to determining that the benefit isless than the predefined threshold, participation kernel 1720 can beconfigured to abandon participation in the ELDR program for theremainder of the day. Participation kernel 1720 can be configured todetermine the benefit based on the benefit function (an objectivefunction):

$J = {{\sum\limits_{i = 1}^{24}{p_{i}r_{{DA}_{i}}{\max( {{e_{CBL} - e_{{grid}_{i}}},0} )}}} - {\max( {{\sum\limits_{i = 1}^{24}{( {r_{e_{i}} - {r_{{ng}_{i}}\eta_{GT}}} ){\max( {{e_{{grid}_{i}} - e_{gridLL}},0} )}}},0} )}}$

where p_(i) is the participation status of the i^(th) hour in the day.p_(i)=0 if it is not a participation hour or if the hour was not awardedand p_(i)=1 if it is a participation hour or the hour was awarded.r_(DA) _(i) [$/kWh] is the Day-Ahead LMP of the i^(th) hour. e_(CBL)[kW] is the customer baseline load. e_(grid) _(i) [kW] is the i^(th)electricity import in kW. It is the actual electricity import for thehours prior to the current time and the estimated electricity import forthe hours in the remainder of the day. r_(e) _(i) [$/kWh]: is theelectricity rate. r_(ng) _(i) [$/kWh] is the natural gas rate. η_(GT) isthe estimated efficiency of the gas turbine. e_(gridLL) [kW]: is thelower limit on the electricity import.

The first term of the benefit function is the total estimated revenuefor the day:

$\sum\limits_{i = 1}^{24}{p_{i}r_{{DA}_{i}}{\max( {{e_{CBL} - e_{{grid}_{i}}},0} )}}$

The second term is the benefit function of the additional electricitybeing imported in order to maintain a high baseline or in other wordsthe opportunity cost. If this additional import were to be generated bygas turbines instead, that would result in a natural gas cost. This iswhy the equivalent natural gas cost is subtracted from the cost ofelectricity import. In the case where the opportunity cost is negative,it means that it would have cost us more to generate the additionalimport to make the revenue. This is why the term is maxed at zero.

In some embodiments, the opportunity cost can be calculated using theelectrical import of the whole day. In other cases without any gasturbines, the opportunity cost can be calculated using only theelectrical import outside of participation hours:

$\max( {{\sum\limits_{i = 1}^{24}{( {r_{e_{i}} - {r_{{ng}_{i}}\eta_{GT}}} ){\max( {{e_{{grid}_{i}} - e_{gridLL}},0} )}}},0} )$

At every dispatch, participation kernel 1720 can be configured to makeits participation decision based on whether the benefit is above thethreshold or not and the NBT threshold value, predicted real-time LMP,and day-ahead LMP. If the benefit is greater than the threshold, thenparticipation kernel 1720 can be configured to continue to participatefor the remainder of the day. If the benefit gets to a point where it isbelow the threshold, then the decision would be to quit participatingfor the remainder of the day. Participation kernel 1720 can beconfigured to abandon the remainder of the day by setting theparticipation mask to zeros and keeping the participation mask at zerosfor the remainder of the day. Determining to abandon participation for aparticular day may result in an updated bid being sent to CSP 1704.

In some embodiments, participation kernel 1720 can perform the benefittest for the current day of operation and/or for every day over aparticular horizon. The additional advantage of this approach is thatthe NBT threshold value can be continued to be used as is without abuffer and for those days where there only few hours of participation,the benefit would end up being lower than the pre-determined thresholdand thus choose to opt out of participation.

In some embodiments, the benefit threshold is $1,000. Since the DA-LMPcan be used in the determination of the benefit, it should be noted thatat higher prices and if the first hour is not getting dispatched, itwould take us couple of hours until participation for the day isabandoned.

Referring now to FIGS. 18A-18B a process 1800 is shown for dynamicallyadapting control of building equipment for an ELDR program, according toan exemplary embodiment. Process 1800 can be performed by a computingdevice, e.g., ELDR module 1706. Although process 1800 is described withreference to ELDR module 1706, any computing device described herein canbe configured to perform process 1800.

In step 1802, ELDR module 1706 can collect ELDR parameters from CSP 1704and/or collect electric load values for a building. For example, theELDR parameters may be real-time LMP values collected by real-time LMPcollector 1708, day-ahead LMP values collected by the day-ahead LMPcollector 1710, and/or NBT threshold values collected by NBT pricecollector 1714. The electric load values may be historic load datacollected by building status monitoring devices. For example, in FIG.10, a building status monitor 624 collects historic electric load data.

Step 1802 may be a periodic step, i.e., the ELDR parameters can becollected periodically. In some embodiments, each of the ELDR parametersis collected at a particular period. Process 1800 performs anoptimization to determine bids, electric load reduction amounts, andoptimal operating load values for building equipment. Since the ELDRparameters are collected periodically, the optimization of process 1800can adapt to changes in the ELDR parameters over time.

In step 1804, ELDR module 1706 can predict the ELDR parameters and/orthe electric load values of the building into the future. Predictor 1718can predict a day-ahead LMP into the future, a real-time LMP into thefuture, and/or the electric load values of the building. These predictedvalues can be provided by predictor 1718 to participation kernel 1720for determination of the participation hours.

In step 1806, based on the predicted ELDR parameters and the predictedelectric load values, ELDR module 1706 can generate participation hoursand determine participation amounts for each of the participation hours.The participation hours may be determined by participation kernel 1720according to the methods described in FIGS. 10-12. For each of theparticipation hours, optimizer 1722 can determine a participationamount, an amount that ELDR module 1706 will reduce its electric load bywith reference to a CBL. Furthermore, optimizer 1722 can determineoptimal electric loads for building equipment of the building. Theelectric loads of the building equipment may be loads which cause thebuilding equipment to consume an amount of energy such that theparticipation amount for each of the participation hours isappropriately met and/or revenue generated by participating in the ELDRprogram is maximized.

In step 1808, ELDR module 1706 can provide a bid to CSP 1704 based onthe participation hours and participation amounts determined in step1806. More specifically, bid submitter 1716 can submit a bid, includingthe participation hours and the participation amount for eachparticipation hour to CSP 1704. In step 1810, based on the determinedoptimal electric loads of the step 1808, ELDR module 1706 can controlthe building equipment. Controlling the building equipment based on thedetermined optimal electric loads may cause the building equipment tooperate at control parameters that cause the optimal electric load to berealized.

Responsive to submitting a bid, CSP 1704 may award some, none, or all ofthe bid participation hours. Awarded bids collector 1712 can collect theindication of whether an hour is awarded or not. Based on the awarded orrejected participation hours, future allocation of the buildingequipment and/or future participation in the ELDR program can beupdated, steps 1814-1822 describe this dynamic adjustment in furtherdetail.

In step 1814, ELDR module 1706 can generate a user interface fordisplaying the received awarded bids of step 1812, the actual and/orpredicted ELDR parameters, the participation hours, and the estimatedparticipation amounts. More specifically, user interface manager 1724 ofELDR module 1706 can generate the user interface. In some embodiments,the user interface is the same as and/or similar to the user interfacesshown in FIGS. 23-31. The user interface may display information to auser and receive various overrides from the user. For example, the userinterface may indicate that a particular hour of a particular day is aparticipation hour for participating in the ELDR program. If a user doesnot want to participate in that hour, the user can indicate an overrideof the hour and the optimization of step 1820 can reflect the updates tothe user preferred participation. In step 1816, user interface manager1724 can receive the overridden participation hours from the userinterface.

Based on submitted bid of step 1808, awarded bids collector 1712 canreceive awarded and/or rejected participation hours from CSP 1704. Morespecifically, awarded bids collector 1712 can be configured to determinewhich hours are awarded or not awarded by reading the awarded hours fromCSP 1704.

Based on the awarded hours (step 1818), overridden participation hours(step 1816), and changes to the ELDR parameters which may beperiodically collected (step 1802), ELDR module 1706 can determinesecond participation hours, second participation amounts for theparticipation hours, and second optimal electric loads for the buildingequipment. Step 1820 may be similar to step 1806 but may be a seconditeration of step 1806. The determination of participation hours,participation amounts, and optimal electric loads may be performed on aperiodic basis to account for changes in the ELDR parameters, awardedbids, and/or user overrides. Although only two iterations of thedetermination are shown in process 1800, there may be any number ofiterations performed. For example, after step 1820, ELDR module 1706 cansubmit a second bid (e.g., perform step 1808 again), receive moreawarded or rejected bids (e.g., perform step 1812 again), collect moreELDR parameters (e.g., perform step 1802 again), receive more overriddenhours (e.g., perform step 1818 again) and finally perform step 1820again.

In step 1822, ELDR module 1706 can control the building equipment basedon the second optimal electric loads. The second optimal electric loadsmay be the same as or different than the first electric loads. In thisregard, the performance of the building equipment can adapt to changesin participation, awarded hours, overrides, changes in ELDR parameters,etc.

Referring now to FIG. 19, a process 1900 for determining whether tocontinue participation in the ELDR program or abort participation in theELDR program in response to receiving rejected participation hours isshown, according to an exemplary embodiment. Process 1900 can beperformed by a computing device, e.g., ELDR module 1706. Althoughprocess 1900 is described with reference to participation kernel 1720 ofELDR module 1706, any computing device described herein can beconfigured to perform process 1900.

When participating in the ELDR program, ELDR module 1706 may determineoptimal electric load amounts for building equipment to be high duringbaseline hours. Baseline hours may be hours where the load of a facilityduring the baseline hours is used to determine the CBL for the facility.By raising the value of the CBL, the ELDR module 1706 can maximizerevenue when curtailing energy usage. However, the baseline hours usedto determine the CBL are based on the first awarded participation hourfor a day. In this regard, if the first bid participation hour of ELDRmodule 1706 is not accepted, ELDR module 1706 has raised the optimalelectric load for no benefit. In this regard, process 1900 determineshow ELDR module 1706 should respond to participation hours beingrejected by CSP 1704.

In step 1902, participation kernel 1720 can generate an ELDR benefitfunction. The ELDR benefit function can indicate revenue generated fromparticipating in an ELDR program. The benefit function may be:

$J = {{\sum\limits_{i = 1}^{24}{p_{i}r_{{DA}_{i}}{\max( {{e_{CBL} - e_{{grid}_{i}}},0} )}}} - {\max( {{\sum\limits_{i = 1}^{24}{( {r_{e_{i}} - {r_{{ng}_{i}}\eta_{GT}}} ){\max( {{e_{{grid}_{i}} - e_{gridLL}},0} )}}},0} )}}$

where p_(i) is the participation status of the i^(th) hour in the day.p_(i)=0 if it is not a participation hour or if the hour was not awardedand p_(i)=1 if it is a participation hour or the hour was awarded.r_(DA) _(i) [$/kWh] is the Day-Ahead LMP of the i^(th) hour. e_(CBL)[kW] is the customer baseline load. e_(grid) _(i) [kW] is the i^(th)electricity import in kW, it is the actual electricity import for thehours prior to the current time and the estimated electricity import forthe hours in the remainder of the day. r_(e) _(i) [$/kWh] is theelectricity rate. r_(ng) _(i) [$/kWh] is the natural gas rate. η_(GT) isthe estimated efficiency of the gas turbine. e_(gridLL) [kW]: is thelower limit on the electricity import.

In step 1904, awarded bids collector 1712 can receive indicationsregarding whether particular bid participation hours have been awardedor rejected. The indication of the awarded or rejected participationhours can be provided by awarded bids collector 1712 to participationkernel 1720. Step 1904 may be similar to and/or the same as step 1812 ofprocess 1800 as described with reference to FIG. 18A.

In step 1906, participation kernel 1720 can determine the revenue fromparticipating in the ELDR program based on the ELDR benefit functionbased on the received indications of whether participation hours wereawarded or rejected. In step 1908, participation kernel 1720 cancontinue participating in the ELDR program for the current day inresponse to determining that the revenue of step 1906 is greater than apredefined amount. However, if the revenue is less than the predefinedamount, the participation kernel 1720 can determine to stopparticipating in the ELDR program for the particular day (step 1910). Tostop participating in the ELDR program for the particular day,participation kernel 1720 can set all of the participation statuses ofall the participation hours to zero.

Referring now to FIG. 20, a timeline 2000 illustrating the collection ofvarious ELDR parameters by ELDR module 1706 is shown for a particularhour, according to an exemplary embodiment. Timeline 2000 illustratesthe ELDR parameters collected by real-time LMP collector 1708, day-aheadLMP collector 1710, awarded bids collector 1712, and awarded bidscollector 1712. Timeline 2000 illustrates collection events forreal-time LMP (event 2002), collection events for awarded bids,(collection event 2006), collection events for day-ahead LMP (collectionevent 2008), and a collection event for the NBT threshold (collectionevent 2004). In timeline 2000, the real-time LMP is shown to becollected by real-time LMP collector 1708 at five minute intervals withthe first collection of the hour occurring at 12:01. However, thecollection of the real-time LMP may occur at any interval. Thecollection of the NBT threshold value by NBT price collector 1714 isshown to occur once in a particular day, in the timeline 2000 at 12:05P.M. Finally, day-ahead LMP collector 1710 can collect the day-ahead LMPvalues. In timeline 2000, the day-ahead LMP values are shown to becollected at a thirty minute interval.

Referring now to FIGS. 21 and 22, electric load levels are shown on aday where the CSP 1704 rejects participation hours at the beginning ofthe day and ELDR module 1706 attempts to keep the CBL high, according toan exemplary embodiment. FIGS. 21 and 22, via graphs 2100, 2200, and2300, provide an example of the problem that may occur if participationkernel 1720 does not perform process 1900 to determine whether or not toabandon participation in the ELDR program for a particular day. Forexample, as shown in graphs 2100 and 2200, all the participation hourswere rejected except for hours 16:00 (e.g., 4:00 PM), 17:00 (e.g., 5:00PM), 18:00 (e.g., 6:00 PM), and 19:00 (e.g., 7:00 PM). The electricload, indicated by marker 2102, is shown to be kept high all day sincethe early morning participation hours were rejected. It may not beworthwhile to keep the electric load high for such a long time precedingthe awarded participation hours that occur late in the day. Therefore,process 1900 of FIG. 19 performed by participation kernel 1720 canidentify whether or not to abandon participation in the ELDR program fora particular day.

Referring generally to FIGS. 23-31, interfaces 2400 and 2900 are shownfor providing ELDR information to a user and receiving hours overridesfrom the user, according to an exemplary embodiment. Interfaces 2400 and2900 can be generated by user interface manager 1724. A user, via a userdevice (e.g., user device 1013) can view interfaces 2400 and/or 2900. Insome embodiments, interface manager 1724 causes user device 1013 togenerate and display interfaces 2400-2900. In some embodiments,interfaces 2400 and 2900 are accessed via a web browser of interfacemanager 1724. In some embodiments, interfaces 2400 and 2900 aregenerated based on an application running on user device 1013.

ELDR module 1706 can automate participation in the ELDR program.Therefore, a user interface may be necessary to view and/or override theautomated decisions and participation of ELDR module 1706. ELDR module1706 may partially or fully remove the user from making decisions in theELDR program. However, the user may be able to monitor the performanceof ELDR module 1706 via user interfaces 2400 and/or 2900. All and/orsome of the data used to make the various participation hour decisionsby participation kernel 1720 can be displayed in user interfaces 2400and/or 2900 for user review. Furthermore, the participation hoursoverridden used by participation kernel 1720 to determine theparticipation hours can be generated by user interface manager 1724based on the decisions input by the user via interfaces 2400 and/or2900.

Referring to FIG. 23, interface 2400 is shown in greater detail,according to an exemplary embodiment. Interface 2400 is shown to includea graph 2402. Graph 2402 can be a plot of ELDR parameters and actualand/or determined electric load values for a building and/or campus.

User interface manager 1724 can be configured to generate graph 2402based on data collected by collectors 1708-1714 and/or bid submitter1716. Graph 2402 may display hourly and/or sub-hourly data. For example,the real-time LMP collected by real-time LMP collector 1708 can beplotted as real-time LMP 2408 in graph 2402. The day-ahead LMP collectedby day-ahead LMP collector 1710 is plotted as day-ahead LMP 2410 ingraph 2402. The electric load determined by optimizer 1722 and/or amonitored actual electric load (e.g., an electric load monitored bybuilding status monitor 624) can be plotted as electric load 2412 ingraph 2402. A baseline, a CBL, can be determined by interface manager1724 and plotted as baseline 2414 so that a user viewing graph 2402 hasa reference to see the load reduction. Finally, the curtailment amount,the difference between the baseline and the electric load for aparticipation hour, is marked by area 2416.

Graph 2402 is shown to display the hours for a particular day. Theparticular day is indicated by date 2420. In some embodiments, graph2402 displays predicted data trends. For example, the predictedreal-time LMP, the predicted day-ahead LMP, and/or the predicted campusload, all predicted by predictor 1718 can be displayed in graph 2402.Graph 2402 can also display overridden pricing, e.g., an overriddenreal-time LMP and/or an overridden day-ahead LMP that a user maymanually define. Furthermore, graph 2402 can display an indication ofthe NBT threshold value, the indication marked by 2418.

Chart 2404 can display participation hours for participating in the ELDRprogram for multiple hours of a day and/or multiple hours of multipledays. The participation hours determined by participation kernel 1720can be displayed in the chart along with an indication of the loadreduction amount associated with the participation hour. Furthermore,chart 2404 may identify which hours, if any, were overridden by a user.For example, a user may add an override to cause participation kernel1720 to define a particular hour as a participation hour even if itotherwise would not determine that the overridden hour is aparticipation hour. Similarly, the user can override a participationhour determined by participation kernel 1720 if the user does not wantto participate in a particular hour that participation kernel 1720determines.

In some embodiments, chart 2404 indicates which participation hours areawarded by CSP 1704 and/or which hours are rejected by CSP 1704. In someembodiments, the current hour is highlighted to indicate the currenttime to the user. Furthermore, chart 2404 may indicate which hours arelocked and cannot be overridden by a user. In some embodiments, thehours lock a predefined amount of time before they occur. For example,an hour may become locked three hours before the override can occur.

In some embodiments, interface 2400 indicates a total revenue generatedfor a particular day. In some embodiments, interface 2400 may provide anindication of a predicted revenue for a particular day and continuouslyupdate the total revenue throughout the day. Similarly, interface 2400may display a total and/or average curtailment amount for a day. Thetotal and/or average curtailment amount can be a predicted and/or actualvalue. In some embodiments, the total and/or average curtailment amountis updated continuously throughout the day.

Both graph 2402 and chart 2404 can display data for part of or an entireday, i.e., from midnight to midnight. The user can view current and/orpast information via the graph 2402 and chart 2404 (e.g., the past sixtydays of information) and can navigate through the past information.Chart 2404 can display both the hours of the current day and the hoursof days into the future (e.g., nine days into the future). Furthermore,chart 2404 can allow a user to perform a navigation action to displaymore days into the future (e.g., swipe up or scroll down). For example,user interface manger 1724 may store past data and/or may otherwise beable to retrieve past data (e.g., retrieve past data from the ELDRparameter database 1709).

The overrides that the user can make via interface 2400 can includeparticipation overrides and pricing overrides. The user can overrideparticipation hours on an hour by hour basis if the participation hoursare not yet locked (e.g., the hours may become locked within at apredefined amount of time into the future). Interface 2400 may providean indication of which hours are overridden and what the originaldecision for the hour was. Interface 2400 may simultaneously display theuser override decision, whether to participate or not participate at theparticular hour, and the decision to participate or not participate asdetermined by participation kernel 1720.

Furthermore, a user can override the real-time LMP and/or the day-aheadLMP via interface 2400. The user can override the values for thereal-time LMP and/or the day-ahead LMP on an hour by hour basis (or caninput a constant value for a particular day). The user may only be ableto override the prices for an hour a predefined amount of time beforethe hour occurs. Hours that are locked, e.g., the current hour plus thethree following hours, the user may not be able to override with anoverridden price. Interface 2400 may display both the user overriddenprice and/or the original and/or actual price. This data may bedisplayed simultaneously in the user interface.

Interface 2400 is shown to include a selector 2406 for operating ineither an advisory mode or an auto mode. When the auto mode is selected,ELDR module 1706 can be configured to participate automatically withoutany user input. When the advisory mode is selected, ELDR module 1706 canbe configured to participate automatically but take into account useroverrides. In some embodiments, when the advisory mode is selected, theELDR program may not be executed by ELDR module 1706.

Referring now to FIG. 24, interface 2400 is shown in greater detaildisplay participation decisions for multiple hours and days into thefuture, according to an exemplary embodiment. As shown in FIG. 24,participation decisions and participation amounts are shown in chart2404. Some of the hours are marked as participation hours with theassociated participation amounts. The participation hours and theparticipation amounts can be determined by the participation kernel 1720and optimizer 1722. An example of a participation hour is the hourmarked by 2506. A user can be able to edit and override theseparticipation hours, in addition to the hours where no participation hasbeen determined.

Furthermore, a user can override an hour where no participation has beendetermined, for example, the hour marked by 2504. However, some hoursmay be locked once they are within a predefined time into the future.For example, the hour marked by 2502 is a locked hour and a user cannotoverride the locked hour. An example of a past participation hour and anindication of the participation amount for the past participation houris marked by 2500. Graph 2402 is shown to include a pop-up window 2508.When a user hovers over the graph 2402 at a particular location, thevalues for the plotted ELDR parameters can be displayed to the userbased on the time associated with the location where the user hoveredand the values of the ELDR parameters associated with the particulartime can be displayed.

Referring now to FIG. 25, interface 2400 to include overriddenparticipation hours and past participation hours, according to anexemplary embodiment. An example of an overridden participation hour ishour 2602. Hour 2602 can be an hour where the user indicated thatparticipation should not occur. All of the hours shown in FIG. 25 arepast hours, these are hours which have already occurred and ELDR module1706 may have already participated in. Hour 2604 provides an example ofa past hour where no participation in the ELDR program occurred.Referring now to FIG. 26, another example of user interface 2400 isshown, according to an exemplary embodiment. FIG. 26 is an example wherethe ELDR module 1706 determines it is best to participate only a smallamount of hours, six hours total in this case, for a particular day.

Referring now to FIG. 27, yet another example of user interface 2400 isshown. In FIG. 27, a large number of days are participated in, for thedate of Jan. 31, 2018, every possible hour of participation is shown. Inboth FIGS. 26 and 27, some hours of the days are permanently locked.Morning hours 2702 and the evening hours 2704 are shown to be locked.These hours may be unsupported hours, i.e., hours that the ELDR programdoes not allow participation. In some embodiments, the hours are betweenmidnight and 4:00 A.M. (the morning hours 2702) and between 9:00 P.M.and midnight (the evening hours 2704). Furthermore, user interface 2400can display a time 2706 which may correspond to a dispatch time. Thedispatch time may be the next time that the awarded bids collector 1712will attempt to collect the awarded bids from CSP 1704.

Referring now to FIG. 28, interface 2900 is shown in detail, accordingto an exemplary embodiment. Interface 2900 is shown to include multipletabs, an input data tab 2912 and an economic load demand response tab2914. Input data tab 2912 is shown in greater detail in FIG. 31. Ineconomic load demand response tab 2914, tables 2902-2906 are shown.Table 2902 illustrates the various participation hours. The hours may bemarked as either a one or a zero, a one indicating participation while azero indicates no participation. Hours that are locked may be displayedin a first color (red), e.g., hours 2916 are shown to be locked hours,hour 2918 is shown to be the current hour, while hours 2920 are shown tobe past hours.

Table 2904 can display a curtailment amount for each of theparticipation hours. For an hour where there is no participation hour,where table 2902 indicates a zero, the corresponding entry of table 2904may also be a zero. However, for an hour with participation, where table2902 indicates a one, the corresponding entry of table 2904 may indicatethe amount of the participation. Furthermore, table 2906 may indicatethe revenue generated for each hour. Legend 2910 may indicate variouscolors, patterns, or other visual markers for actual past hours, thecurrent hour, an overridden hour, and a locked in hour. Element 2908 mayallow a user to navigate between various different days and view ELDRparticipation information for various different days.

Referring now to FIG. 29, interface 2900 is shown to allow a user toselect and override various hours, according to an exemplary embodiment.In FIG. 29, non-participation hours 3002 are shown to be selected by auser. The user may interact with the participation button 3000 causingall of the selected hours to become participation hours. Likewise, theuser could select participation hours and cause the participation hoursto become non-participation hours.

Referring now to FIG. 30, interface 2900 is shown to include a plot ofELDR parameters and an indication of overridden participation hours,according to an exemplary embodiment. The interface 2900 is shown toinclude plot 3100 which may plot various ELDR parameters. Plot 3100 maybe similar to and/or the same as graph 2402 as described with referenceto FIGS. 23-27. Interface 2900 is shown to include override box 3104which presents a user with an button to add an override and/or remove anoverride. If a user selects a particular hour of table 2902 and pressesthe override button, the hour may be overridden (e.g., overridden from aparticipation hour to a non-participation hour or from anon-participation hour to a participation hour). The user can alsoremove the override, returning the participation decision to thedecision made by ELDR module 1706.

In FIG. 30, overridden hours 3108 are shown. These hours can be shaded aparticular color to indicate to a user which hours of table 2902 havebeen overridden. If the user hovers a cursor over overridden hours 3108,a pop-up 3106 may be displayed indicating both the user overridedecision and the decision of ELDR module 1706.

Referring now to FIG. 31, input data tab 2912 is shown in greaterdetail, according to an exemplary embodiment. If the user interacts withinput tab 2912, interface 2900 may display graphs 3200 and 3202 as shownin FIG. 31. The graphs may be graphs of ELDR parameters, in FIG. 31, thegraphs are of values for the day-ahead LMP and the real-time LMP. Eachof the graphs 3299 and 3202 can be broken into two sections, past values3204 and 3208, and future values 3206 and 3210. The past values may beactual values collected from CSP 1704 while future values may be valuespredicted by predictor 1718.

Configuration of Exemplary Embodiments

The construction and arrangement of the systems and methods as shown inthe various exemplary embodiments are illustrative only. Although only afew embodiments have been described in detail in this disclosure, manymodifications are possible (e.g., variations in sizes, dimensions,structures, shapes and proportions of the various elements, values ofparameters, mounting arrangements, use of materials, colors,orientations, etc.). For example, the position of elements can bereversed or otherwise varied and the nature or number of discreteelements or positions can be altered or varied. Accordingly, all suchmodifications are intended to be included within the scope of thepresent disclosure. The order or sequence of any process or method stepscan be varied or re-sequenced according to alternative embodiments.Other substitutions, modifications, changes, and omissions can be madein the design, operating conditions and arrangement of the exemplaryembodiments without departing from the scope of the present disclosure.

The present disclosure contemplates methods, systems and programproducts on any machine-readable media for accomplishing variousoperations. The embodiments of the present disclosure can be implementedusing existing computer processors, or by a special purpose computerprocessor for an appropriate system, incorporated for this or anotherpurpose, or by a hardwired system. Embodiments within the scope of thepresent disclosure include program products comprising machine-readablemedia for carrying or having machine-executable instructions or datastructures stored thereon. Such machine-readable media can be anyavailable media that can be accessed by a general purpose or specialpurpose computer or other machine with a processor. By way of example,such machine-readable media can comprise RAM, ROM, EPROM, EEPROM, CD-ROMor other optical disk storage, magnetic disk storage or other magneticstorage devices, or any other medium which can be used to carry or storedesired program code in the form of machine-executable instructions ordata structures and which can be accessed by a general purpose orspecial purpose computer or other machine with a processor. Combinationsof the above are also included within the scope of machine-readablemedia. Machine-executable instructions include, for example,instructions and data which cause a general purpose computer, specialpurpose computer, or special purpose processing machines to perform acertain function or group of functions.

Although the figures show a specific order of method steps, the order ofthe steps may differ from what is depicted. Also two or more steps canbe performed concurrently or with partial concurrence. Such variationwill depend on the software and hardware systems chosen and on designerchoice. All such variations are within the scope of the disclosure.Likewise, software implementations could be accomplished with standardprogramming techniques with rule based logic and other logic toaccomplish the various connection steps, processing steps, comparisonsteps and decision steps.

What is claimed is:
 1. An energy optimization system for a building, thesystem comprising: a processing circuit configured to: perform anoptimization to generate one or more first participation hours and afirst energy adjustment amount for each of the one or more firstparticipation hours; generate a user interface comprising an indicationof one or more operation parameters for an energy program, the one ormore first participation hours, and the first energy adjustment amountfor each of the one or more first participation hours; receive one ormore overrides of the one or more first participation hours from theuser interface; perform the optimization a second time to generate oneor more second participation hours for participating in the energyprogram, and a second energy adjustment amount for each of the one ormore second participation hours for the one or more pieces of buildingequipment based on the received one or more overrides; and operate theone or more pieces of building equipment to affect an environmentalcondition of the building.
 2. The system of claim 1, wherein theprocessing circuit is configured to: provide a first bid comprising theone or more first participation hours and the first energy adjustmentamount for each of the one or more first participation hours to acomputing system configured to facilitate the energy program; andprovide a second bid comprising the one or more second participationhours and the second energy adjustment amount for each of the one ormore second participation hours to the computing system configured tofacilitate the energy program, wherein the second bid is an update tothe first bid, the one or more second participation hours are an updateto the one or more first participation hours, and the second energyadjustment amount for each of the one or more second participation hoursis an update to the first energy adjustment amount for each of the oneor more first participation hours.
 3. The system of claim 1, wherein theuser interface comprises: a first interface element indicating valuesfor one or more energy parameters; and a second interface elementindicating the one or more first participation hours and the firstenergy adjustment amount for each of the one or more first participationhours.
 4. The system of claim 3, wherein the one or more energyparameters comprise one or more awarded or rejected hours of the one ormore first participation hours, wherein the processing circuit isconfigured to cause the second interface element to display anindication of which of the one or more first participation hours areawarded hours or which of the one or more first participation hours arerejected hours.
 5. The system of claim 3, wherein the second interfaceelement is a chart indicating a plurality of hours for a plurality ofdays and an indication of which of the plurality of hours for theplurality of days are the first participation hours and the first energyadjustment amount for each of the one or more first participation hours.6. The system of claim 3, wherein the processing circuit is configuredto: cause the second interface element to display a locked indicationfor each of the one or more first participation hours a predefinedamount of time before each of the one or more participation hoursoccurs; and prevent a user from overriding each of the one or more firstparticipation hours within the predefined amount of time before each ofthe one or more first participation hours.
 7. The system of claim 3,wherein the first interface element is a trend graph indicating a trendof the values for the one or more energy parameters for a plurality oftimes; wherein the processing circuit is configured to: collect thevalues for the one or more energy operation parameters from a computingsystem configured to facilitate the energy program; generate the trendgraph based on the collected values for the one or more energy operationparameters; and cause the user interface to include the generated trendgraph.
 8. The system of claim 7, wherein the one or more energyparameters comprise at least one of a day ahead locational marginalprice which is an electricity price for a particular area on a futureday, or a real-time locational marginal price which is an electricityprice on at a current time.
 9. The system of claim 7, wherein theprocessing circuit is configured to: receive one or more electricconsumption values from the building equipment configured to measure theelectrical consumption values; cause the trend graph to include a trendof the one or more electric consumption values; generate a baselineelectrical load based on historic electric load consumption; and causethe trend graph to include an indication of the baseline electricalload.
 10. A method for optimizing energy use of a building, the methodcomprising: performing an optimization to generate one or more firstparticipation hours and a first energy adjustment amount for each of theone or more first participation hours; generating a user interfacecomprising an indication of one or more energy operation parameters foran energy program, the one or more first participation hours, and thefirst energy adjustment amount for each of the one or more firstparticipation hours; receiving one or more overrides of the one or morefirst participation hours from the user interface; performing theoptimization a second time to generate one or more second participationhours for participating in the energy program, a second energyadjustment amount for each of the one or more second participationhours, and one or more second equipment loads for the one or more piecesof building equipment based on the received one or more overrides; andoperating the one or more pieces of building equipment to affect anenvironmental condition of the building based on the one or more secondequipment loads.
 11. The method of claim 10, further comprising:providing a first bid comprising the one or more first participationhours and the first energy adjustment amount for each of the one or morefirst participation hours to a computing system configured to facilitatethe energy program; and providing a second bid comprising the one ormore second participation hours and the second energy adjustment amountfor each of the one or more second participation hours to the computingsystem configured to facilitate the energy program, wherein the secondbid is an update to the first bid, the one or more second participationhours are an update to the one or more first participation hours, andthe second energy adjustment amount for each of the one or more secondparticipation hours is an update to the first energy adjustment amountfor each of the one or more first participation hours.
 12. The method ofclaim 10, wherein the user interface comprises: a first interfaceelement indicating values for one or more energy parameters; and asecond interface element indicating the one or more first participationhours and the first energy adjustment amount for each of the one or morefirst participation hours.
 13. The method of claim 12, wherein thesecond interface element is a chart indicating a plurality of hours fora plurality of days and an indication of which of the plurality of hoursfor the plurality of days are the first participation hours and thefirst energy adjustment amount for each of the one or more firstparticipation hours.
 14. The method of claim 13, further comprising:causing the second interface element to display a locked indication foreach of the one or more first participation hours a predefined amount oftime before each of the one or more participation hours occurs; andpreventing a user from overriding each of the one or more firstparticipation hours within the predefined amount of time before each ofthe one or more first participation hours.
 15. The method of claim 13,wherein the first interface element is a trend graph indicating a trendof the values for the one or more energy parameters for a plurality oftimes; wherein the method further comprises: collecting the values forthe one or more energy operation parameters from a computing systemconfigured to facilitate the energy program; generating the trend graphbased on the collected values for the one or more energy operationparameters; and causing the user interface to include the generatedtrend graph.
 16. The method of claim 15, wherein the one or more energyparameters comprise at least one of a day ahead locational marginalprice which is an electricity price for a particular area on a futureday, or a real-time locational marginal price which is an electricityprice on at a current time.
 17. The method of claim 15, furthercomprising: receiving one or more electric consumption values frombuilding equipment configured to measure the electrical consumptionvalues; causing the trend graph to include a trend of the one or moreelectric consumption values; generating a baseline electrical load basedon historic electric load consumption; and causing the trend graph toinclude an indication of the baseline electrical load.
 18. An energyoptimization controller for a building, the controller comprising: aprocessing circuit configured to: perform an optimization to generateone or more first participation hours and a first energy adjustmentamount for each of the one or more first participation hours; generate auser interface comprising an indication of one or more energy operationparameters for an energy program, the one or more first participationhours, and the first energy adjustment amount for each of the one ormore first participation hours, wherein the user interface comprises: afirst interface element indicating values for one or more energyparameters; and a second interface element indicating the one or morefirst participation hours and the first energy adjustment amount foreach of the one or more first participation hours; receive one or moreoverrides of the one or more first participation hours from the userinterface; perform the optimization a second time to generate one ormore second participation hours for participating in the energy program,and a second energy adjustment amount for each of the one or more secondparticipation hours based on the received one or more overrides; andoperate the one or more pieces of building equipment to affect anenvironmental condition of the building.
 19. The controller of claim 18,wherein the processing circuit is configured to: provide a first bidcomprising the one or more first participation hours and the firstenergy adjustment amount for each of the one or more first participationhours to a computing system configured to facilitate the energy program;and provide a second bid comprising the one or more second participationhours and the second energy adjustment amount for each of the one ormore second participation hours to the computing system configured tofacilitate the energy program, wherein the second bid is an update tothe first bid, the one or more second participation hours are an updateto the one or more first participation hours, and the second energyadjustment amount for each of the one or more second participation hoursis an update to the first energy adjustment amount for each of the oneor more first participation hours.
 20. The controller of claim 18,wherein the processing circuit is configured to: cause the secondinterface element to display a locked indication for each of the one ormore first participation hours a predefined amount of time before eachof the one or more participation hours occurs; and prevent a user fromoverriding each of the one or more first participation hours within thepredefined amount of time before each of the one or more firstparticipation hours.